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American Electric Power 2009 AEP-SPP (Public Service Company of Oklahoma & Southwestern Electric Power Company) integrated resource plan : 2010-2019.

2009 AEP-SPP
(Public Service Company of Oklahoma & Southwestern Electric Power Company)
INTEGRATED RESOURCE PLAN
2010-2019
Date Issued: July 2009
Business Confidential
Copy Control # ______
AEP-SPP 2009 Integrated Resource Plan
The Integrated Resource Plan (IRP) is based upon the best available
information at the time of preparation. However, changes that may impact this
plan can, and do, occur without notice. Therefore this plan is not a
commitment to a specific course of action, since the future, now more than
ever before, is highly uncertain, particularly in light of the current economic
conditions, access to capital, the movement towards increasing use of
renewable generation and end-use efficiency, as well as legislative proposals to
control “greenhouse gases.”
The implementation action items as described herein are subject to change as
new information becomes available or as circumstances warrant. It is AEP’s
intention to revisit and refresh the IRP annually.
.
The contents of this report contain the Company’s forward-looking projections and recommendations
concerning the capacity resource profile of its affiliated operating companies located in the Southwest
Power Pool (SPP) Regional Transmission Organization. This report contains information that may be
viewed by the public. Business sensitive information has been excluded from this document, but will
be made available in a confidential supplement on an as needed basis to third parties subject to
execution of a confidentiality agreement. The confidential supplement should be considered strictly
business sensitive and proprietary and should not be duplicated or transmitted in any manner. Any
questions or requests for additional copies of this document should be directed to:
Scott C. Weaver
Managing Director—Resource Planning and Operational Analysis
Corporate Planning & Budgeting
(614) 716-1373 (audinet: 200-1373)
scweaver@aep.com
AEP-SPP 2009 Integrated Resource Plan
AEP-SPP 2009 Integrated Resource Plan
Table of Contents
Executive Summary................................................................................................................. i
1.0 Introduction...................................................................................................................... 1
1.1 IRP Process Overview ................................................................................................................. 1
1.2 Introduction to AEP ..................................................................................................................... 1
2.0 Current Resource Planning Issues in the Electric Utility Industry ............................. 7
2.1 Regulation/Deregulation .............................................................................................................. 7
2.2 Climate Change and Greenhouse Gases.......................................................................................7
2.3 Role and Impact of Commodity Pricing on Planning ................................................................ 12
2.4 Issues Summary ......................................................................................................................... 18
3.0 Implications of Industry Issues in this IRP Cycle........................................................ 21
3.1 Demand Response/Energy Efficiency (DR/EE) ........................................................................ 21
3.2 Renewables ............................................................................................................................... 21
3.3 Carbon Capture & Storage/Sequestration (CCS) ....................................................................... 22
3.4 Emission Compliance ................................................................................................................ 22
4.0 Current Resources .......................................................................................................... 25
4.1 Existing PSO and SWEPCO Generating Resources .................................................................. 25
4.2 Capacity Impacts of Environmental Compliance Plan .............................................................. 25
4.3 Existing Unit Disposition........................................................................................................... 26
4.4 AEP-SPP Transmission.............................................................................................................. 26
5.0 Demand Projections........................................................................................................ 35
5.1 Load and Demand Forecast - Process Overview ....................................................................... 35
5.2 Peak Demand Forecast............................................................................................................... 36
5.3 Current DR/EE Programs........................................................................................................... 38
6.0 Capacity Needs Assessment ........................................................................................... 41
6.1 RTO Requirements .................................................................................................................... 42
6.2 Capacity Positions—Historical Perspective............................................................................... 43
7.0 Planning Objectives ........................................................................................................ 45
7.1 Planning Flexibility—Covering Capacity Deficient Positions with Market Opportunities....... 45
7.2 Planning Horizon ....................................................................................................................... 45
7.3 Establishing the Optimal Asset “Mix”....................................................................................... 45
7.4 Other Operational Factors .......................................................................................................... 45
7.5 Affordability.............................................................................................................................. 46
8.0 Resource Options ............................................................................................................ 47
8.1 Market Options and “Build vs. Buy” Considerations ................................................................ 47
8.2 Traditional Capacity-Build Options........................................................................................... 49
8.3 Renewable Alternatives ............................................................................................................. 54
8.4 Carbon Capture .......................................................................................................................... 61
8.5 Demand Side Alternatives.......................................................................................................... 62
9.0 Evaluating DR/EE Impacts for the 2009 IRP .............................................................. 67
9.1 gridSMARTSM........................................................................................................................... 67
9.2 Demand Response/Energy Efficiency Mandates and Goals ...................................................... 67
9.3 Assessment of Achievable Potential .......................................................................................... 68
9.4 Determining Programs for the IRP ............................................................................................ 69
9.5 Optimizing the Incremental DR/EE Resources.......................................................................... 71
9.6 Discussion and Conclusion ........................................................................................................ 74
10.0 Fundamental Modeling Parameters............................................................................ 77
AEP-SPP 2009 Integrated Resource Plan
10.1 Modeling and Planning Process—An Overview..................................................................... 77
10.2 Methodology........................................................................................................................... 77
10.3 Key Fundamental Modeling Input Parameters ........................................................................ 78
11.0 Resource Portfolio Modeling ....................................................................................... 81
11.1 The Strategist Model—An Overview...................................................................................... 81
11.2 Strategist Optimization............................................................................................................ 83
11.3 AEP–SPP Supply-side Resource “Type” Options/Characteristics.......................................... 83
11.4 AEP-SPP DR/EE and Renewable Resource Options/Characteristics ..................................... 84
11.5 PSO Plan Development ........................................................................................................... 85
11.6 SWEPCO Plan Development .................................................................................................. 97
12.0 Risk Analysis ............................................................................................................... 107
12.1 The URSA Model.................................................................................................................. 107
12.2 URSA Modeling Results ....................................................................................................... 108
12.3 Capital Cost Risk Assessment ............................................................................................... 111
12.4 Results Including Capital Cost Risk ...................................................................................... 111
12.5 Conclusion From Risk Modeling........................................................................................... 114
13.0 Conclusions and Recommendations.......................................................................... 115
13.1 Capacity and Energy Plan...................................................................................................... 115
13.2 Comparison to 2008 IRP ....................................................................................................... 121
13.3 Plan Impact on Carbon Mitigation (“Prism” Analysis) ......................................................... 121
13.4 Arkansas Stakeholder Process - SWEPCO............................................................................ 124
13.5 Conclusion............................................................................................................................ 125
14.0 Implementation ........................................................................................................... 127
14.1 Current Commitments ........................................................................................................... 127
AEP-SPP 2009 Integrated Resource Plan
Exhibits
Exhibit 1-1: IRP Process Overview.......................................................................................................................2
Exhibit 1-2: AEP System, East and West Zones ....................................................................................................3
Exhibit 1-3: PSO Reserve Margin With and Without Exelon PPA........................................................................4
Exhibit 1-4: SWEPCO Reserve Margin With and Without Turk and Stall Plants .................................................4
Exhibit 2-1: Fossil Fuel-to-Electricity Emissions, by Fuel Type ...........................................................................7
Exhibit 2-2: CO2 Price Forecast .............................................................................................................................8
Exhibit 2-3: Renewable Standards by State ...........................................................................................................9
Exhibit 2-4: CO2 Capture and Sequestration Process...........................................................................................11
Exhibit 2-5: Power Price Layers..........................................................................................................................12
Exhibit 2-6: SPP On-Peak Price Index.................................................................................................................13
Exhibit 2-7: Natural Gas Price Index ...................................................................................................................13
Exhibit 2-8: PRB Coal Price Index ......................................................................................................................14
Exhibit 2-9: SO2 Emission Price Index ................................................................................................................17
Exhibit 2-10: CO2 Emission Price Index..............................................................................................................17
Exhibit 2-11: 2H08 vs. 1H09 Commodities Comparison.....................................................................................20
Exhibit 3-1: Renewable Energy Plan Through 2030............................................................................................22
Exhibit 4-1: Existing PSO and SWEPCO Generating Resources ........................................................................25
Exhibit 4-2: PSO and SWEPCO Capacity Change After June 2009....................................................................26
Exhibit 5-1: Load and Demand Forecast Process—Sequential Steps ..................................................................35
Exhibit 5-2: AEP-SPP Peak Demand and Energy Projection...............................................................................37
Exhibit 5-3: AEP-SPP Current DR/EE Programs full-year impacts ....................................................................40
Exhibit 6-1: Capacity vs. SPP Minimum Required Reserves...............................................................................41
Exhibit 6-2: Summary of Capacity Deficiency Position ......................................................................................42
Exhibit 6-3: AEP-SPP, Historical Capacity Position ...........................................................................................43
Exhibit 8-1: Projected SPP Capacity Margin ......................................................................................................47
Exhibit 8-2: Recent Merchant Generation Purchases ...........................................................................................48
Exhibit 8-3: United States Wind Power Locations...............................................................................................56
Exhibit 8-4: United States Solar Resource Locations...........................................................................................57
Exhibit 8-5: Land Area Required to Support Biomass Facility ............................................................................58
Exhibit 8-6: Biomass Resources in the United States...........................................................................................59
Exhibit 8-7: Renewable Sources Included in AEP-SPP and East 2009 IRP ........................................................60
Exhibit 8-8: Typical DR/EE Measure Conservation Load Factor........................................................................65
Exhibit 9-1: Impact of Legislation on Energy Consumption................................................................................67
Exhibit 9-2: Achievable Versus Technical Potential (Illustrative) .......................................................................68
Exhibit 9-3: AEP-SPP Zone Cost Effectiveness of Relative Programs................................................................70
Exhibit 9-4: AEP-SPP Zone DR/EE Proxy Blocks ..............................................................................................71
Exhibit 9-5: AEP-SPP Zone DR/EE Modeling Constraints .................................................................................72
Exhibit 9-6: AEP-SPP Zone DR/EE Blocks Selected in Resource Modeling (AEP-SPP)...................................73
Exhibit 9-7: AEP-SPP Internal EE Target versus IRP .........................................................................................74
Exhibit 9-8: AEP-SPP Zone DR/EE Assumption Summary ................................................................................75
Exhibit 10-1: Long-term Forecast Process Flow..................................................................................................78
Exhibit 10-2: Input Scenarios and Sensitivities....................................................................................................79
Exhibit 11-1: AEP Sponsored DSM Programs.....................................................................................................85
Exhibit 11-2: Comparison of PSO Optimal and Suboptimal Plans ......................................................................86
Exhibit 11-3: PSO Optimal Plan Comparison for Power and CO2 Price Scenarios .............................................87
Exhibit 11-4: PSO Full Study Period Revenue Requirements .............................................................................88
Exhibit 11-5: PSO Full Study Period Cost over Optimal Plan .............................................................................88
Exhibit 11-6: PSO Plan Comparisons ..................................................................................................................90
Exhibit 11-6: PSO Plan Comparisons (Cont’d)....................................................................................................91
Exhibit 11-7: PSO Load Forecast Trends.............................................................................................................92
Exhibit 11-8: PSO Load Forecast Comparison ....................................................................................................93
Exhibit 11-9: PSO Reserve Margin......................................................................................................................94
Exhibit 11-10: PSO Hybrid Plan ..........................................................................................................................95
AEP-SPP 2009 Integrated Resource Plan
Exhibit 11-11: Comparison of SWEPCO Optimal and Suboptimal Plans ...........................................................98
Exhibit 11-12: SWEPCO Optimal Plan Comparison for Power and CO2 Price Scenarios ..................................99
Exhibit 11-13: SWEPCO Full Study Period Revenue Requirements.................................................................100
Exhibit 11-14: SWEPCO Full Study Period Cost over Optimal Plan ................................................................100
Exhibit 11-15: SWEPCO Plan Comparisons......................................................................................................101
Exhibit 11-15: SWEPCO Plan Comparisons (Cont’d) .......................................................................................102
Exhibit 11-16: SWEPCO Hybrid Plan ...............................................................................................................103
Exhibit 11-17: SWEPCO Load Forecast Comparisons ......................................................................................104
Exhibit 11-18 SWEPCO Reserve Margin With and Without Turk and Stall Plants ..........................................105
Exhibit 12-1A: Key Risk Factors–Weighted Means for 2009-2035 (PSO)........................................................107
Exhibit 12-1B: Key Risk Factors–Weighted Means for 2009-2035 (SWEPCO)...............................................108
Exhibit 12-2A: Cumulative Probability Distribution of AEP-SPP Revenue Requirement (PSO)......................109
Exhibit 12-2B: Cumulative Probability Distribution of AEP-SPP Revenue Requirement (SWEPCO).............109
Exhibit 12-3A: Probability Distribution of AEP-SPP Revenue Requirement (PSO) .........................................110
Exhibit 12-3B: Probability Distribution of AEP-SPP Revenue Requirement (SWEPCO).................................110
Exhibit 12-4: Basis of Capital Cost Distributions ..............................................................................................111
Exhibit 12-5A: Capital Cost Risk-Adjusted CPW 2009-2035 Revenue Requirement ($ Millions) (PSO) ....... 111
Exhibit 12-5B: Capital Cost Risk-Adjusted CPW 2009-2035 Revenue Requirement ($ Millions) (SWEPCO)111
Exhibit 12-6A: Distribution Function for All Portfolios (PSO) .........................................................................112
Exhibit 12-6B: Distribution Function for All Portfolios (SWEPCO).................................................................113
Exhibit 12-7A: Distribution Function for All Portfolios at > 95% Probability (PSO) .......................................113
Exhibit 12-7B: Distribution Function for All Portfolios at > 95% Probability (SWEPCO)...............................114
Exhibit 13-1: AEP-SPP Generation Capacity.....................................................................................................116
Exhibit 13-2: AEP-SPP Current Capacity Mix ..................................................................................................117
Exhibit 13-3: AEP-SPP 2019 Capacity Mix.......................................................................................................117
Exhibit 13-4: 2008 AEP-SPP 2030 Capacity Mix..............................................................................................118
Exhibit 13-5: Change in Energy Mix With Hybrid Plan - Current vs. 2019 and 2030.......................................119
Exhibit 13-6: 2009 AEP-SPP IRP ......................................................................................................................121
Exhibit 13-7: CO2 Emission Profile ...................................................................................................................122
Exhibit 13-8: CO2 Emission Profile With Caps..................................................................................................123
Exhibit 13-9: CO2 Emission Profile vs. Estimated Waxman-Markey Allocation ..............................................124
AEP-SPP 2009 Integrated Resource Plan
Appendices
Appendix A, Figure 1 Existing Generation Capacity, AEP-SPP Zone ..............................................................131
Appendix B, Figure 1 Economically Screened Renewable Alternatives ...........................................................132
Appendix C, Figure 1 Key Supply Side Resource Assumptions........................................................................133
Appendix C, Figure 2 Energy Storage Screening...............................................................................................134
Appendix D, Figure 1 AEP-SPP Capacity, Demand, Reserve Forecast.............................................................135
Appendix D, Figure 2 AEP-SPP Capacity, Demand, Reserve Forecast (High Demand Scenario)....................136
Appendix D, Figure 3 PSO Capacity, Demand, Reserve Forecast ....................................................................137
Appendix D, Figure 4 SWEPCO Capacity, Demand, Reserve Forecast ...........................................................138
Appendix E, Figure 1 AEP Plan to Meet 10% of Renewable Energy Target by 2020.......................................139
Appendix F, DSM By Operating Company .......................................................................................................140
Appendix G, Arkansas Stakeholder Report........................................................................................................141
AEP-SPP 2009 Integrated Resource Plan
Acknowledgements
The Resource Planning group appreciates the support and input of the various individuals
throughout the Service Corporation who provided input into the development of this Integrated
Resource Plan document. In addition, a number of people provided valuable comments as the report
was being developed including the operating company regulatory support staffs.
AEP-SPP 2009 Integrated Resource Plan
i
Executive Summary
The goal of resource planning is to match a utility’s future suite of resources with projected
demand for those resources. As such the plan lays out the amount, timing and type of resources that
achieve this goal at the lowest reasonable cost, considering all the various constraints – reserve
margins, emission limitations, renewable and energy efficiency requirements – that it is mandated to
meet. Planning for future resource requirements during volatile periods can be challenging.
Unprecedented economic contraction and varying levels of proposed regulation regarding greenhouse
gases and renewable energy are two major drivers of uncertainty that must be addressed during the
planning process. Over the 10-year, 2010-2019 Integrated Resource Plan (IRP or “Plan”) planning
period, the AEP’s integrated western zone (AEP-SPP) which includes Public Service Company of
Oklahoma (PSO) and Southwestern Electric Power Company (SWEPCO) is expected to experience
load growth at a compound annual rate of 1.5% per year, or roughly 140 MW annually. This growth
can be considered as occurring in two phases. The impact of the existing recession depresses peak
demand in 2009 and 2010 with a rapid increase in 2011 from the assumed economic recovery. In
addition, there is a comparable rate of growth for internal energy sales over the 10-year period, with
load factors increasing in 2011 due to the recovery of recession impacted industrial load.
The following Summary Exhibit 1 depicts the “going-in” capacity needs of PSO and SWEPCO
with committed capacity additions (Stall and Turk for SWEPCO, Exelon-Green Country PPA for
PSO) but excluding uncommitted planned capacity additions. It amplifies that the recent economic
downturn has reduced the need for new resources, beyond current commitments, to the end of the
planning horizon. However, PSO and SWEPCO must still make resource additions to satisfy reserve
requirements.
With the supply side additions and demand side measures that provide demand
reductions/energy efficiency (DR/EE or “DSM”) included in this 2009 IRP, Summary Exhibit 2
shows that PSO and SWEPCO will be able to meet their margin requirements without market
capacity purchases beginning in 2013.
AEP-SPP 2009 Integrated Resource Plan
ii
Summary Exhibit 1
PSO: Capacity Position
NO New Capacity Post-2012 L/T PPA…. NO 'New' Energy Efficiency/Demand Reduction (EE/DR)
2,500
3,000
3,500
4,000
4,500
5,000
5,500
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Year
MW- Summer Capacity
Installed Capacity (MW) Purchased Capacity (MW)
Est. Long-Term PPA Capacity (MW) Demand + SPP Margin (MW) (Nov 2008 Fcst)
Demand + SPP Margin (MW) (April 2009 Fcst)
SWEPCo: Capacity Position
NO New Capacity Post-Turk…. NO 'New' Energy Efficiency/Demand Reduction (EE/DR)
2,500
3,000
3,500
4,000
4,500
5,000
5,500
6,000
6,500
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Year
MW- Summer Capacity
Installed Capacity (MW) Purchased Capacity (MW)
Stall (2011) + Turk (2013) (MW) Demand + SPP Margin (MW) (Nov 2008 Fcst)
Demand + SPP Margin (MW) (April 2009 Fcst)
Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan
iii
Summary Exhibit 2
AEP SPP: (Summer Season)
Reflecting: Current Hybrid Plan
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Year
MW- Summer Capacity
Installed/Purchased Capacity (MW) New Capacity (MW)
Demand + SPP Margin (MW)(W/ DSM) Demand + SPP Margin (MW)(W/O New DSM)
Source: AEP Resource Planning
Both the proposed Turk (SWEPCO) baseload ultra-supercritical pulverized coal (USC-PC) plant
and a 509 MW Stall Natural Gas Combined Cycle were considered embedded for 2009 AEP-SPP
resource planning purposes, as they were secured during the SWEPCO 2006 Long-term Baseload
Resource Request For Proposal (RFP) process. These units are currently under construction with Stall
approximately 60% physically complete—with 95 % of the construction costs committed—and
scheduled to begin commercial operation prior to the summer peak of 2011 and Turk approximately
15% physically complete—with 81 % of the construction costs committed—and scheduled to be in
service prior to the summer peak of 2013. The 2008 PSO RFP process resulted in the selection of a
purchase power agreement (PPA) with Exelon for 512 MW of the Green Country combined cycle
facility which is also embedded in this IRP beginning 2012. Each project is fulfilling commission-approved
findings of need/necessity in Arkansas, Louisiana, Texas (Stall and Turk), and Oklahoma
(450 MW of baseload capacity), and are still required for meeting SPP minimum reserve margin
requirements.
AEP-SPP 2009 Integrated Resource Plan
iv
Major Drivers:
Global Climate Change
This 2009 IRP for AEP-SPP is consistent with the AEP 2009 Corporate Sustainability Report
with regard to the assumption of potential legislation related to greenhouse gas (GHG)/carbon dioxide
(CO2) emissions, renewable portfolio standards (RPS), and energy efficiency. The driving planning
assumptions include:
 CO2 mitigation in the form of substantive CO2 reduction legislation effective by 2015 with a
cap-and-trade regime effective in the same year.
 Prospect of a future Federal RPS, or a growing critical mass or “patchwork” of AEP state-legislated
RPS initiatives—which could be in the range of 10%, or more.
With that, AEP has positioned itself by assuming an aggressive posture in the adoption of
renewable alternatives including a 2,000 MW system-wide renewable initiative (by 2011).
That strategy would be an underpinning of an overall renewable energy target of 10% of
sales by 2020 and is consistent with the existing state renewable energy targets.
Demand Side Management and Energy Efficiency (DR/EE)
Recognizing the prospects of higher (avoided) costs, AEP initiatives to improve grid efficiency
and install advanced metering, and a national groundswell focused on efficiency, the AEP-SPP IRP
calls for:
 Approximately 78 MW of incremental DR/EE by 2010, growing to 389 by 2019.
 This is “incremental” since it is over-and-above current estimates of existing AEP-SPP
interruptible-type measures totaling over 48 MW at peak. However, it is inclusive of current
and pending energy efficiency programs at both PSO and SWEPCO.
Wind and Other Renewable Resources
Along with the prospects of CO2 legislation, the possible introduction of a Federal (or “en
masse” state) RPS, helped justify the planned system-wide purchase of 2,000 MW of renewable
resources—for planning purposes assumed to be in the form of wind power—by 1/31/2011. The
largest portion of these purchases is for AEP-East.1 When added to current and planned PSO and
SWEPCO long-term wind purchases as well as economically-screened wind and biomass co-firing
opportunities beyond the 10-year IRP period, these operating companies as well as AEP are
positioned to achieve 10% of energy sales from renewable sources.
Emerging Technology
AEP is committed to pursuing emerging technologies that fit into the capacity resource planning
process, including Sodium Sulfur (NaS) Batteries, fuel cells, solar panels, and “smart” grid enabling
meters. These “distributed” technologies, while currently expensive relative to traditional demand
1 Note: Firm “capacity” attributable to wind would be limited to roughly 8%, of the nameplate amount for
purposes of capacity planning in SPP.
AEP-SPP 2009 Integrated Resource Plan
v
and supply options, have the capacity to evolve into common resource options as costs come down
and the capabilities continue to improve. For each of these options, both the technology and
associated costs will continue to be monitored for increased inclusion in future planning cycles, if
warranted.
AEP-SPP Recommended Plan:
Complete the 509 MW Stall combined Cycle Facility in SWEPCO by the by the third quarter
of 2011 so it is ready for the summer peak in 2011
 Begin receipt of 512 MW of baseload/intermediate capacity from Green Country (Exelon
PPA) in PSO by summer of 2012
 Complete the joint owned (AEP share - 447 MW) Turk Ultra-Supercritical PC plant in
SWEPCO by the fourth quarter of 2012 so it is ready for the summer peak in 2013
 Purchase (or construction) of an additional 750 MW (nameplate) of wind generation by 2019
 Acquire 158 MW of peaking capacity in SWEPCO by 2019
Implement new DR/EE programs totaling 332 MW over the IRP planning period, or over 860
GWH annually after 2015.
The following Summary Exhibit 3 offers a view of the 2009 AEP-SPP IRP:
Summary Exhibit 3
RENEWABLE RENEWABLE
Environmental
Retrofits(G)
Embedded
Demand
Reduction(B)
(Cumul.
Contribution)
New
Demand
Reduction(C)
(Cumul.
Contribution)
Wind (Nameplate)
Environmental
Retrofits(G)
E mbedded
Demand
Reduction(B)
(Cumul. Contribution)
New
Demand
Reduction(C)
(Cumul.
Contribution)
Wind (Nameplate)
2009 9 0 10 0
2010 13 31 16 24 79.5(F)
2011 16 62 198 (E) 20 48 100
2012 19 94 24 72 100
2013 21 125 26 96 150
2014 22 157 FC1 (4) 29 120
2015 23 188 67 WSH2 (8) 30 144 33
2016 NE3&4 (15) 24 188 31 144 100
2017 25 188 200 32 144
2018 25 188 32 144
2019 25 188 32 144
Nameplate
Capacity
(15) 25 188 465 (12) 32 144 563
(SPP) Capacity
Value (Wind 8%; )
60 45
Cumul.
(Nameplate) 2% 16% 39% 2% 8% 30%
Cumul.
(Capacity)
Contribution 3% 24% 8% 2% 11% 42%
(G) Derate associated with the addition of and FGD system
Planned
Resource
Reductions
Planned
Resource
Reductions
PSO SWEPCO
THERMAL
Duty Cycle Type:
BL=Baseload
INT=Intermediate
PKG=Peaking
(Stall) 509-MW INT
2009 AEP-SPP Integrated Resource Plan (Hybrid Plan)
(B) "Embedded" DSM represents 'known & measurable', commission-approved program activity now projected by AEP-Economic Forecasting in the most recent
load forecast
157-MW PKG
1,113
Planned Resource Additions (MW) Planned Resource Additions (MW)
DSM
(E) Assumes Elk City and Blue Canyon V wind energy available by 2011, but firm transmission delayed until 2013
(C) "New" DSM represents incremental activity projected based on estimated contribution & program cost (vs. avoided cost) parameters, from recent Market Potential
Studies, and were generally limited to an EPRI Jan. '09 study identifying a "Realistically Achievable Potential". This 'New' (increm) DSM-DR activity modeled thru
2015 only
(D) PPA term for PSO 2012 baseload capacity & energy: 9 years, 7 months (thru 2021)
(Turk) 447-MW BL
DSM THERMAL
Duty Cycle Type:
BL=Baseload
INT=Intermediate
PKG=Peaking
(F) Assumes Majestic wind energy available by 2010, but firm transmission delayed until 2012
43%
(Grn Cntry PPA)
512-MW BL
60%
(A) Not shown are relatively small unit uprates and derates embedded in the current plan (e.g. FGD retrofit auxliary load losses)
512
65% 83%
Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan
vi
Plan Impact on Carbon Mitigation (“Prism” Analysis)
Global Climate Change and the prospect for comprehensive CO2 legislation has had a direct
bearing on the outcome of the 2009 AEP-SPP Plan. To gauge the respective CO2 mitigation impacts
incorporated into this resource planning, an assessment was performed that emulates an approach
undertaken by the Electric Power Research Institute (EPRI). This profiling seeks to measure the
contributions of various “portfolio” components that could, when taken together, effectively achieve
such carbon mitigation:
 Energy Efficiency
 Renewable Generation
 Fossil Plant Efficiency, including coal-unit retirements
 Nuclear Generation
 Technology Solutions, including Carbon Capture and Sequestration
The following Summary Exhibit 4 reflects those comparable components within this 2009 IRP–set
forth as uniquely-colored “prisms”—that are anticipated to contribute to the overall AEP System’s
(combined East and West regions) initiatives to reduce its carbon footprint:
Summary Exhibit 4
AEP-SYSTEM (East & West)
CO2 Emission Profile
Hybrid Plan (2009 IRP)
Including: 20 MW CCS by 20 1 0… 235 MW by 2013… 1,300 MW by 2020… 1,740 MW by 2025… 5,800 MW by 2030
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
CO2 Emissions, K Tonnes
(Pre-Committed) NSR Caps & Retirements
DR/EE
Renewables
Retirements (post-'R/R/R')
Cook Uprates
CCS Retrofits @ 90%
Hybrid Plan
2009 Hybrid Plan
(Assuming No Carbon Offsets or
Allowance Purchases)
"Business-As-Usual"
2005 (A)
144.9 M
62.5 M
Tonne
(35.8%)
Reduction
Source: AEP Resource Planning
While these results would suggest significant improvement in the AEP System CO2 emission
profile over time, it could still fall short of prospective legislation that would attempt to further limit
AEP-SPP 2009 Integrated Resource Plan
vii
CO2. Specifically, using H.R. 2454 (the Waxman-Markey Bill) that passed the U.S. House in June,
2009 as a proxy, this profile would require reduction in CO2 emissions that would have to consider
acquisition of carbon “offsets”—financial instruments that represent certified initiative to remove 1
ton of carbon—to begin to approximate the levels of reduction set forth by such mandates. The
following Summary Exhibit 5 offers such a comparison for the AEP System:
Summary Exhibit 5
AEP-SYSTEM (East & West)
CO2 Position vs. W-M Emission "Caps"
Hybrid Plan (2009 IRP)
Including: 20 MW CCS by 2010… 235 MW by 2013… 1,300 MW by 2020… 1,740 MW by 2025… 5,800 MW by 2030
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
CO2 Emissions, K Tonnes
(Pre-Committed) NSR Caps & Retirements
DR/EE
Renewables
Retirements (post-'R/R/R')
Cook Uprates
CCS Retrofits
Offsets (Domestic & Int'l)
Hybrid Plan with Offsets
W-M CO2 Target
62.5 M
Tonne
(35.8%)
Reduction
Waxman-Markey
(Physical Compliance) Targets
(3% by '12… 17% by '20… 42% by '30)
Assuming
20 M Tonne
of Carbon Offsets
Attainable by 2020
Source: AEP Resource Planning
Further, under the assumption that a cap-and-trade mechanism could emerge from any set of
carbon legislation, it is reasonable to assume that such CO2 mitigation efforts, inclusive of offset
acquisitions, may not provide for an adequate CO2 position within that mechanism. Specifically, if the
legislation provides for the allocation of an insufficient level of (free) CO2 allowances to the utility,
any such remaining CO2 position “shortfall” must subsequently be borne by the utilities’ customers
through additional, potentially more costly, CO2 mitigation efforts, including the purchase of
additional allowances. The following Summary Exhibit 6 identifies this potential position based on
the current allowance allocation format set forth by the Waxman-Markey Bill:
AEP-SPP 2009 Integrated Resource Plan
viii
Summary Exhibit 6
AEP-SYSTEM (East & West)
CO2 Position vs. Est. W-M LDC Allocations & Wholesale Recoveries
Hybrid Plan (2009 IRP)
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
CO2 Emissions, K Tonnes
(Pre-Committed) NSR Caps & Retirements
DR/EE
Renewables
Retirements (post-'R/R/R')
Cook Uprates
CCS Retrofits
Offsets (Domestic & Int'l)
Hybrid Plan with Offsets
W-M CO2 Target
Wholesale Allow. Recovery
W-M LDC Est. Allowance Alloc.
62.5 M
Tonne
(35.8%)
Reduction
~40 MM
Allowances
Required (2012)
~24 MM
Allowances
Required (2020)
or...
~4,800 MW "CCS-Equiv."
(@ ~5 MM T per 1GW CCS)
~69 MM
Allowances
Required (2030)
or...
~13,800 MW "CCS-Equiv."
(@ ~5 MM T per 1GW CCS)
Est. Utility (Retail) Allow. Allocation @
79 MM in 2012 under W-M "50/50"
distribution basis for Electricty Sector
allowance alloc
Waxman-Markey
(Physical Compliance)
Target
(17% by '20… 42% by '30)
Est. increm. allowance/cost
recovery from Wholesale
Customers
Source: AEP Resource Planning
In summary, this prism analysis would suggest that the carbon mitigation requirements in the
AEP System (East and SPP) 2009 IRPs offer a meaningful pathway to the attainment of potential
Climate Change/CO2 legislation, however, additional contributions–over-and-above the acquisition
of CO2 allowances—may be required in future planning cycles to protect AEP’s customers from
significant cost exposures.
Plan Impact on Capital Requirements
This Plan includes new capacity additions, as well as unit uprates and environmental retrofits.
Such generation additions require a significant investment of capital. Some of these projects are still
conceptual in nature, others do not have site specific information to perform detailed estimates;
however, it is important to provide an order of magnitude cost estimate for the projects included in
this plan. As some of the initiatives represented in this plan span both East and West AEP zones, this
Summary Exhibit 7 includes estimates for projects over the entire AEP system Generation (G)
functional discipline.
It is important to reiterate the capital spend level reflected on the Summary Exhibit 7 is
“incremental” in that it does not include “base”/business-as-usual capital expenditure requirements of
the “G” sector. Achieving this additional level of expenditure will therefore be a significant challenge
going-forward and would suggest the Plan itself will remain under constant evaluation and subject to
change.
AEP-SPP 2009 Integrated Resource Plan
ix
Summary Exhibit 7
Reflecting...
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 TOTAL Group %
By Type… (2010-2019)
IRP (New Generation) 362 306 321 110 175 281 306 302 177 634 2,974 25%
IRP (Response to Carbon / RPS Legislation) - - - 44 147 381 349 548 848 623 2,941 24%
362 306 321 154 322 662 655 850 1,025 1,257 5,915
Plus:
Environmental Compliance / Cook License Extension 58 242 519 794 1,039 1,297 866 839 439 33 6,126 51%
TOTAL INCREMENTAL "G" CAPEX 420 548 840 948 1,361 1,959 1,521 1,689 1,464 1,290 12,041
Annual % 3% 5% 7% 8% 11% 16% 13% 14% 12% 11%
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 TOTAL
By Operating Company… (2010-2019)
AEG 4 5 90 37 50 135 246 370 220 17 1 ,172
APCo 14 15 14 15 98 298 251 546 723 582 2 ,555
CSP 0 0 13 30 70 98 9 0 100 125 4 44
I&M 30 90 110 152 352 684 642 470 220 93 2 ,842
KPCo 2 18 100 150 190 154 102 90 5 0 8 11
OPCo 4 3 33 95 164 188 73 69 30 89 7 48
PSO 0 5 63 203 258 331 129 23 153 271 1 ,436
SWEPCO 366 412 417 267 179 72 70 122 15 114 2 ,033
TOTAL INCREMENTAL "G" CAPEX 420 548 840 948 1,361 1,959 1,521 1,689 1,464 1,290 12,041
Subtotal
AEP System (East & West)
PRELIMINARY (Incremental) "G" Capex Spend
2009 IRP (E&W)
Assuming 1,300 MW CCS (MT only ) by 2020… (w/ 1,740 MW by 2025 … 5,800 MW by 2030 )
2010-2019
($Millions)
Source: AEP Resource Planning
Conclusion:
The recommended plan provides the “lowest, reasonable cost” solution through a
combination of traditional supply, renewable and demand side investments. The tempered load
growth combined with additional renewable resources, increased DR/EE initiatives, completion of
Stall and Turk plants, and the execution of the Exelon PPA, will allow AEP-SPP to meet its resource
requirements through 2018 at which point new peaking capacity will be required. No new
uncommitted baseload capacity is required over the term of the forecast period.
Keep in mind that the planning process is a continuous activity; assumptions and plans are
continually reviewed as new information becomes available and are modified as appropriate. Indeed,
the resource expansion plan reported herein reflects, to a large extent, assumptions that are subject to
change. It is simply a snapshot of the future at this time. The Plan is not a commitment to a specific
course of action. The future, now more than ever before, is highly uncertain, particularly in light of
the current economic conditions, the movement towards increasing use of renewable generation and
end-use efficiency, as well as legislative proposals to control “greenhouse gases” which could result
in the retirement or retrofit of existing generating units, impacting the supply of capacity and energy
to AEP-SPP companies. The resource planning process is becoming increasingly complex given
pending legislative and regulatory restrictions, technology advancement, changing energy supply
fundamentals, uncertainty of demand and energy efficiency advancements all of which necessitate
flexibility in any ongoing plan. The ability to invest in capital-intensive infrastructure is increasingly
challenged in light of current economic conditions, and the impact on the AEP-SPP customers will
continue to be a primary planning consideration.
AEP-SPP 2009 Integrated Resource Plan
1
1.0 Introduction
This document contains the assumptions and steps required to develop the recommended
resource plan. Section 1 discusses the company and the resource planning process in general. Section
2 describes emerging industry issues and commodity forecasts that impact utilities including AEP.
Section 3 describes the implications of these issues as they relate to resource planning. Section 4
describes current supply resources, including transmission integration, and Section 5 discusses
projected growth in demand and energy which serves as the underpinning of the plan. Then Section 6
combines these two projected states (resources versus demand) to identify the need to be filled.
Sections 7 through 12 describe the analysis and assumptions that are used to develop the plan such as
planning objectives (Section 7), resource options (Section 8), evaluation of demand side measures
(Section 9), and fundamental modeling parameters (Section 10). The modeling process and portfolio
development, including the selection of the “Hybrid Plan” is covered in Section 11, and finally a risk
analysis of selected portfolios is performed in Section 12. Section 13 describes the findings and
recommendations and lastly, Section 14 describes the plan implementation.
1.1 IRP Process Overview
This report presents the results of the Integrated Resource Plan (IRP) analysis for the AEP-SPP
zone of the AEP System, covering the period 2009-2019, with additional planning modeling and
analyses conducted through the year 2030. The information presented with this IRP (“Plan”) includes
descriptions of assumptions, study parameters, methodologies, and results including the integration of
supply-side resources and demand-side management (DSM) programs. The IRP process is displayed
graphically in Exhibit 1-1.
The goal of the IRP process is to identify the amount, timing and type of resources required to
ensure a reliable supply of power and energy to customers at the least reasonable cost.
In addition to the need to set forth a long-term strategy for achieving regional reliability/reserve
margin requirements, capacity resource planning is critical to AEP due to its impact on:
 Determining Capital Expenditure Requirements—which represents one of the basic
elements of the Company’s long-term business plan.
 Rate Case Planning—many of AEP’s regulated operating companies will plan rate
recovery filings that will reflect input based on a prudent planning process.
 Integration with other Strategic Business Initiatives—generation/capacity resource
planning is naturally integrated with the Company’s current and anticipated environmental
compliance, transmission planning, and other corporate planning initiatives such as
gridSMARTsm.
1.2 Introduction to AEP
AEP, with more than five million American customers and serving parts of 11 states, is one of
the country’s largest investor-owned utilities. The service territory covers 197,500 square miles in
Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and
West Virginia.
AEP-SPP 2009 Integrated Resource Plan
2
AEP owns and/or operates 58 generating stations in the United States, with a capacity of
approximately 37,000 megawatts. AEP’s customers are served by one of the world’s largest
transmission and distribution systems. System-wide there are more than 39,000 circuit miles of
transmission lines and more than 213,000 miles of distribution lines.
AEP’s operating companies are managed in two geographic zones for resource planning
purposes. Its SPP zone, which comprises two companies in the Southwest Power Pool (SPP): Public
Service Company of Oklahoma (PSO) and Southwestern Electric Power Company (SWEPCO); and
its eastern zone, comprising Indiana & Michigan Power Company (I&M), Kentucky Power Company
(KPCo), Ohio Power Company (OPCo), Columbus Southern Power Company (CSP), Appalachian
Power Company (APCo), Kingsport Power Company (KgP), and Wheeling Power Company
(WPCo).2
Exhibit 1-1: IRP Process Overview
IRP Process
Integrated
Plan
for
Capacity
Resources
Integrated
Resource
Plan
for
Capacity
Resources
Q1 Q2
“Demand-Side”
Inputs
CP&B, Commercial
Operations
 Load & Demand
Forecast
 (Market) Purchase &
Sale of Firm Capacity &
Energy
 (Incremental) DR/EE
estimates
 Regional (PJM/SPP)
Reserve Requirements
“Supply-Side”
Inputs
Generation,
Commercial
Operations,Trans.
Planning
 Existing Unit Cap.,
Cost & Performance
Parameters
 New & Emerging
Generation Alternatives,
Cost & Perf. Parameters
 (Existing) Gen Oppor.
(Size, type, cost)
 (Emerging)
Transmission Issues &
Constraints
Unit Disposition Evaluation
Generation, Comm Ops, CP&B
 Development of Potential Unit
Retirement Profile
Tranche/Timing
Major Process Input/Parameters
‘MECO’
Modeling
Generation,
Strategic
Policy
Analysis
Least-cost
Environ.
Compliance
Analyses re
SO2, NOx, Hg
Strategist
Resource
Modeling
CP&B
 Least-Cost
Optimal Resource
Plan
 Sensitivity
Analyses (re price,
load, etc.)
 Create multiple
Generation
“Portfolio” Views
Utility Risk Simulation
Analysis (URSA)
Modeling
Market Risk Oversight
 Risk Simulation of Discrete,
Strategist-based LT Portfolios
across “Key Risk Drivers”
BASE
Plan
&
Scenarios
Financial /
Regulatory
Modeling
CP&B
 Financial /
Budgetary
Proformas
 Opco/Juris.
Cost-of-Service
and Revenue
Requirement
Impacts
Iterative Modeling
Iterate, as necessary, based on
emerging issues / planning criteria, risk
profiles, as well as corporate financial
and regulatory recovery constraints.
Plan Develop. & Validation
Emerging Planning Policies / Scenarios
Generation, SPA, Commercial Ops, Transmission Planning, CP&B, Regulatory, Legal
 Add’l Environmental Constraints (e.g. GHG/CO2)… Demand Response/Energy Efficiency / Renewable Portfolio
Standards / Carbon Offsets / Other Emerging Technology Alternatives
 AEP-Ohio, generation/planning ‘status’ post-ESP; other emerging opco/state-specific requirements
 RTO (PJM & SPP) business rule/protocol migrations & LT Transmission Planning (RTEP & STEP)
AEP
Strategic
Plan
Aurora
Funda-mental
Pricing
Modeling
CP&B,Strate-gic
Policy
Analysis,
Generation
Long-term
(regional)
Commodity
Pricing
Forecasts re
Energy,
Natural Gas,
Coals,
Emissions
Modeling within CP&B
Modeling outside of CP&B
Q4 Q3
Document / Filing
Corporate
(E & W) and
Operating
Co./State-specific
Plan
Documentation
and Filings
Louisiana
(rules pending)
Ohio
(rules pending)
Kentucky
Virginia
Indiana
Arkansas
Oklahoma
Source: AEP Resource Planning
2 Both KgP and WPCo are non-generating companies purchasing all power and energy under FERC-approved
wholesale contracts with affiliates APCo and OPCo, respectively. AEP also has two operating companies that
reside in the Electric Reliability Council of Texas (ERCOT), AEP Texas North Company (TNC) and Texas
Central Company (TCC). These companies are essentially “wires” companies only, as neither owns nor
operates generating assets within ERCOT.
AEP-SPP 2009 Integrated Resource Plan
3
Other than a discussion of the requirements of the FERC-approved AEP System Integration
Agreement (SIA), this document will only address 2009 resource planning for the AEP-SPP zone.
Planning for AEP affiliates residing in AEP-East has been communicated in separate documents.
1.2.1 AEP-SPP Zone:
The operating companies in AEP's SPP zone collectively serve a population of about 3.83
million customers (995,050 retail) in a 36,000 square mile area in parts of Arkansas, Louisiana,
Oklahoma, and Texas (see Exhibit 1-2). In 2008, the residential, commercial, and industrial
customers accounted for 29%, 27%, and 27%, respectively, of AEP-SPP's total internal energy
requirements of 42,868 GWh, including energy losses. The remaining 17% was supplied for use in
the other retail and wholesale categories.
AEP-SPP experienced an all-time peak internal demand of 9,120 MW on August 4, 2008. An
all-time winter peak internal demand, 6,902 was experienced on February 16, 2007.The capacity
resource planning of the respective AEP-SPP and East zones is performed on a mutually-exclusive
basis regardless of the covenants of the System Interchange Agreement (SIA).
Exhibit 1-2: AEP System, East and West Zones
Source: AEP Internal Communications
1.2.2 Embedded Baseload Assets
Both the proposed Turk (SWEPCO) baseload ultra-supercritical pulverized coal (USC-PC) plant
and a Stall Combined Cycle (CC) plant were considered embedded for 2009 AEP-SPP resource
planning purposes, as they were secured during the SWEPCO 2006 Long-term Baseload Resource
Request For Proposal (RFP) process. The 2008 PSO RFP process resulted in the selection of a
purchase power agreement (PPA) with Exelon for the 512 MW Green Country combined cycle
Focus of this
IRP
AEP-SPP 2009 Integrated Resource Plan
4
facility which is also embedded in this IRP. These additions were approved by the appropriate state
regulatory commissions based, in part, on the demonstrated need at the time the applications were
filed. During the past year, the economic downturn has lead to reduced load growth forecasts in the
near term. However, SWEPCO and PSO, respectively, still find these facilities necessary to the meet
the peak demand and energy needs of their customers. To illustrate this point, the Exhibit 1-2 for
PSO and Exhibit 1-3 for SWEPCO have been prepared to show the reserve margin exposure with
and without these resources.
Exhibit 1-3: PSO Reserve Margin With and Without Exelon PPA
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Reserve Margin
Under "Base" Demand Forecast:
Per 2009 Resource Plan 13.8% 13.2% 19.2% 19.7% 19.9% 20.3% 19.5% 19.3% 18.7% 18.1%
Exclusive of Exelon PPA (2012) 13.8% 13.2% 6.9% 7.4% 7.6% 7.9% 7.2% 7.1% 6.5% 6.1%
Under "Accelerated (High)" Demand Forecast:
Per 2009 Resource Plan 11.0% 8.2% 15.2% 14.8% 14.2% 14.2% 13.2% 12.6% 11.6% 10.9%
Exclusive of Exelon PPA (2012) 11.0% 8.2% 3.2% 3.0% 2.5% 2.5% 1.5% 1.1% 0.2% -0.5%
Reserve Margin -- MW Position
Above / <Below> 13.6% SPP Requirement)
Under "Base" Demand Forecast:
Per 2009 Resource Plan 6 (18) 232 253 259 275 242 237 211 190
Exclusive of Exelon PPA (2012) 6 (18) (280) (259) (251) (235) (268) (271) (297) (318)
Under "Accelerated (High)" Demand Forecast:
Per 2009 Resource Plan (108) (228) 65 51 26 24 (19) (46) (92) (124)
Exclusive of Exelon PPA (2012) (108) (228) (447) (461) (484) (486) (529) (554) (600) (632)
* Excludes short-term capacity transfers to/from affiliate Southwestern Electric Power Company
Note: Minimum Reserve Margin Requirement per SPP Criteria is 13.6%
PSO
Stand-Alone Reserve Margins*
Based on (April 2009) Demand Forecast "Banding"
10-Year 2009 IRP Period: 2010-2019
Source: AEP Resource Planning
Exhibit 1-4: SWEPCO Reserve Margin With and Without Turk and Stall Plants
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Reserve Margin
Under "Base" Demand Forecast:
Per 2009 Resource Plan 13.8% 14.0% 13.3% 22.0% 20.6% 22.3% 20.9% 19.4% 17.6% 19.2%
Exclusive of Turk (2013) 13.8% 14.0% 13.3% 13.1% 11.9% 12.8% 11.6% 10.1% 8.5% 7.1%
Exclusive of Stall (2011) & Turk (2013) 13.8% 3.7% 3.1% 3.1% 1.9% 2.0% 0.9% -0.4% -1.8% -3.1%
Under "Accelerated (High)" Demand Forecast:
Per 2009 Resource Plan 11.0% 10.6% 9.4% 16.9% 14.9% 15.6% 14.0% 12.0% 10.0% 11.2%
Exclusive of Turk (2013) 11.0% 10.6% 9.4% 8.5% 6.6% 6.6% 5.2% 3.4% 1.5% -0.1%
Exclusive of Stall (2011) & Turk (2013) 11.0% 0.6% -0.4% -1.2% -2.9% -3.6% -4.9% -6.5% -8.2% -9.6%
* Excludes short-term capacity transfers to/from affiliate Public Service Company of Oklahoma
Note: Minimum Reserve Margin Requirement per SPP Criteria is 13.6%
SWEPCO
Stand-Alone Reserve Margins*
Based on (April 2009) Demand Forecast "Banding"
10-Year 2009 IRP Period: 2010-2019
Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan
5
As these exhibits illustrate, reserve margin requirements would fall below the minimum SPP
criteria of 13.6% without these facilities under the most recent load forecast. AEP also prepared an
“Accelerated (High)” Demand Forecast which assumes a more robust recovery from the current
recession. Under this scenario, the need for the embedded assets is even more pronounced.
1.2.3 AEP System Interchange Agreement (East and West)
The 2000 System Interchange Agreement among AEPSC, as agent for the AEP-East, Central
and Southwest Inc. (CSW), and AEP-SPP operating companies, was designed to operate as an
umbrella agreement between the FERC-approved 1997 Restated and Amended CSW Operating
Agreement for its western (former CSW) operating companies and the FERC-approved 1951 AEP
Interconnection Agreement for its eastern operating companies. The System Interchange Agreement
provides for the integration and coordination of AEP’s eastern and western companies’ zones. In that
regard, the SIA provides for the option to transfer capacity and energy between the AEP-SPP zone
and under certain conditions the AEP-East zone. Since the inception of the SIA, AEP has continued
to reserve annually, the transmission rights associated with a prescribed (up to) 250 MW of capacity
from the AEP-East zone to the AEP-West zone. This transmission capacity has now been reserved
through 2013 and this reservation may be extended in five year increments.
1.2.4 AEP-SPP Operating Agreement –Company-Specific Obligations
The fundamental construct for this AEP-SPP IRP is that the initial planning evaluation be
performed on an integrated basis among the applicable operating companies–PSO and SWEPCO–so
as to leverage any opportunities such joint planning may offer as per the Operating Agreement.
Specifically, Section 9.2 of that 1997 Restated and Amended SPP (CSW) Operating Agreement
establishes that “…ownership share in each Joint Unit shall be allocated insofar as practical to
achieve a Prorated Reserve Level for all Companies participating in the Unit.”
However, the Operating Committee of the AEP-West Operating Agreement issued a formal
recommendation in December 2005, stating that the PSO and SWEPCO capacity-build as established
by the 2005 IRP cycle, and embedded within this 2009 IRP cycle, should not be considered for joint-ownership.
This is due to the significant amount of capacity required by both companies for each duty
cycle/type, and the parallel timing of those significant needs.
For the same reasons identified in 2005 by the Operating Committee, at a minimum, the
(embedded) build tranche through the nearer-term 2012 timeframe will naturally continue to be set
forth on a “stand-alone” (PSO and SWEPCO) basis. Therefore, largely for consistency and
considering the current, known intercompany firm transmission constraints between PSO and
SWEPCO that will be discussed in this 2009 report, as well as specific regulatory (needs
determination/cost recovery and competitive bidding) issues, subsequent new capacity resource
tranches (beyond 2012) will also be considered from a company-specific, stand-alone perspective.
That said, the ultimate makeup/ownership of such subsequent AEP-SPP capacity resource tranches
will likewise need to be reconsidered over future planning cycles from a shared-benefit perspective.
AEP-SPP 2009 Integrated Resource Plan
6
AEP-SPP 2009 Integrated Resource Plan
7
2.0 Current Resource Planning Issues in the Electric Utility Industry
2.1 Regulation/Deregulation
Both SWEPCO and PSO are regulated, and are expected to remain regulated throughout the IRP
ten-year period. This includes the portion of SWEPCO’s retail load residing in Texas, but outside of
ERCOT. Texas Senate Bill 547, which was signed into law in May 2009, statutorily delays retail
electric competition for SWEPCO in Texas until the proper infrastructure is in place. The new law
becomes effective September 1, 2009 and virtually assures that SWEPCO will remain regulated
during the period of the IRP.
2.2 Climate Change and Greenhouse Gases
A growing consensus of scientists concludes that the Earth’s climate is warming and that the
warming is due, at least in part, to anthropomorphic production of greenhouse gases (GHG). Many
gases exhibit greenhouse properties; some occur naturally, others are exclusively man-made. While
Carbon Dioxide (CO2) is the most prevalent and significant greenhouse gas in terms of its global
warming potential, there are other major greenhouse gases including methane (CH4), nitrous oxide
(N2O) and chlorofluorocarbons (CFCs).
Gases are typically quoted in terms of either CO2, carbon dioxide equivalents (CO2e) or carbon
equivalents (Ce). CO2 has an atomic weight of 44 while carbon has an atomic weight of 12. Thus,
CO2 equivalents are 3.67 times the mass of carbon equivalents, but the two measures have the same
relative purpose and can be used interchangeably if consistently applied. Anthropomorphic CO2 is
produced primarily from burning fossil fuels, a portion of which is used to produce electricity. In the
U.S., roughly one-third of GHG (measured in CO2e) result from the conversion of fossil fuels to
electricity.
Finally, the fuel and heat rate of the plant used in the production of electricity makes a
difference in the quantity of CO2 produced. Exhibit 2-1 demonstrates the advantage lower heat rates
(Btu/kWh) and fuel types can have.
Exhibit 2-1: Fossil Fuel-to-Electricity Emissions, by Fuel Type
0
0.2
0.4
0.6
0.8
1
1.2
6,000 6,500 7,000 7,500 8,000 8,500 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000
Heat Rate
Tons CO2/MWh
Ultra Super Critical/ IGCC
Super Critical
Existing
Existing Steam
Combustion Turbine
Combined Cycle
Natural Gas
Coal
IGCC
Combined Cycle
Ultra-Supercritical
Supercritical Subcritical
Units with 90% Carbon Capture
Units without Carbon Capture
Natural Gas Coal
Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan
8
2.2.1 Environmental Legislation
The electric utility industry, as a major producer of CO2, will be significantly affected by any
GHG legislation. During the 109th Congress (2005-2006), 106 bills, resolutions, and amendments
specifically addressing global climate change and greenhouse gas emissions were introduced. In
110th Congress, more than 235 bills were introduced that would put controls on the emissions of
greenhouse gases. One Senate bill, Lieberman-Warner, was voted out of the Senate Environmental
Committee and received floor consideration in June 2008. However, after a few days of debate, the
bill failed to pass a Senate cloture vote. The push towards federal climate change legislation is
continuing within the 111th Congress as well. The Waxman-Markey “American Climate and Energy
Security Act of 2009” was recently passed out of the House Energy and Commerce Committee, was
subsequently approved by the House of Representatives in June, and is now being considered by the
Senate. Virtually all of these bills employed “cap and trade” mechanisms (rather than carbon taxes)
with declining CO2 caps over time.
2.2.2 Impact of Environmental Legislation on Industry
Any binding legislation is likely to be “economy-wide”–generally meaning all fossil fuel use
will be targeted–because the production of GHG is not limited to specific sectors. Most legislation
that has been introduced to date is economy-wide. Furthermore, most legislation caps electric utility
emissions “downstream.” That is, electric generator emissions are limited, similar to the EPA’s
current programs that limit utility SO2 and NOx emissions.
2.2.2.1 AEP’s Assumption on CO2 Policy/Price
For the 2009 IRP cycle, the impact of CO2/GHG legislation on AEP’s long-term planning is
essentially modeled as a simple CO2 price beginning in 2015, as shown in Exhibit 2-2, that would
impact fossil unit dispatch cost.
Exhibit 2-2: CO2 Price Forecast
Emissions CO2 Index 2015 $/metric tonne = 1.0
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
CO2 2H08
Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan
9
2.2.2.2 Renewable Portfolio Standards
As identified in Exhibit 2-3, 29 states and the District of Columbia have set standards
specifying that electric utilities generate a certain amount of electricity from renewable sources. Most
of these requirements take the form of “renewable portfolio standards,” or RPS, which require a
certain percentage of a utility sales to ultimate customers come from renewable generation sources by
a given date. The standards range from modest to ambitious, and definitions of renewable energy
vary. Though climate change may not always be the primary motivation behind some of these
standards, the use of renewable energy does deliver significant GHG reductions. For instance, Texas
is expected to avoid 3.3 million tons of CO2 emissions annually with its RPS, which requires 2,000
MW of new renewable generation by 2009.
At the federal level, an RPS ranging from 10-20% was proposed for inclusion in the Energy
Independence and Security Act of 2007; but the final bill as passed into law did not contain an RPS.
However, a combined federal renewable energy standard (RES) and energy efficiency standard (EES)
of 20% was adopted as part of the Waxman-Markey bill passed by the House. The Senate also passed
out of Committee a combined 15% RES/EES and is also considering the House legislation.
Therefore, a federal RPS remains a distinct possibility in 2009 or 2010.
Exhibit 2-3: Renewable Standards by State
Renewable Portfolio Standards
State renewable portfolio standard
State renewable portfolio goal
www.dsireusa.org / July 2009
Solar water heating eligible *†
Extra credit for solar or customer-sited renewables
Includes separate tier of non-renewable alternative resources
WA: 15% by 2020*
OR: 25% by 2025 (large utilities)
5% - 10% by 2025 (smaller utilities)
CA: 20% by 2010
☼ NV: 25% by 2025*
☼ AZ: 15% by 2025
☼ NM: 20% by 2020 (IOUs)
10% by 2020 (co-ops)
HI: 20% by 2020
☼ Minimum solar or customer-sited requirement
TX: 5,880 MW by 2015
UT: 20% by 2025*
☼ CO: 20% by 2020 (IOUs)
10% by 2020 (co-ops & large munis)*
MT: 15% by 2015
ND: 10% by 2015
SD: 10% by 2015
IA: 105 MW
MN: 25% by 2025
(Xcel: 30% by 2020)
☼ MO: 15% by 2021
IL: 25% by 2025
WI: Varies by utility;
10% by 2015 goal
MI: 10% + 1,100 MW
by 2015*
☼ OH: 25% by 2025†
ME: 30% by 2000
New RE: 10% by 2017
☼ NH: 23.8% by 2025
☼ MA: 15% by 2020
+ 1% annual increase
(Class I Renewables)
RI: 16% by 2020
CT: 23% by 2020
☼ NY: 24% by 2013
☼ NJ: 22.5% by 2021
☼ PA: 18% by 2020†
☼ MD: 20% by 2022
☼ DE: 20% by 2019*
☼ DC: 20% by 2020
VA: 15% by 2025*
☼ NC: 12.5% by 2021 (IOUs)
10% by 2018 (co-ops & munis)
VT: (1) RE meets any increase
in retail sales by 2012;
(2) 20% RE & CHP by 2017
29 states & DC
have an RPS
5 states have goals
KS: 20% by 2020
AEP-SPP 2009 Integrated Resource Plan
10
2.2.3 AEP’s Voluntary Greenhouse Gas Mitigation Strategy
2.2.3.1 Plan through 2010
As a founding member of the Chicago Climate Exchange (CCX), AEP committed to
cumulatively reduce or offset 48 million metric tons of CO2 emissions from 2003 to 2010. Through
2008, AEP reduced or offset 51 million metric tons of CO2 — exceeding our target. We’ve done this
in a number of ways, such as improving power plant efficiency, replacing or retiring less efficient and
higher emitting units, increasing our use of renewable power, reducing SF6 emissions and investing in
forestry projects in the United States and abroad. For example, we have signed contracts to add 903
MW of wind capacity in the past two years — about 90 percent of our goal toward adding 1,000 MW
of wind by 2011. Consequently, we will double this goal and add a total of 2,000 MW of renewable
energy by the end of 2011, with regulatory support.
This will help AEP to further diversify its fuel portfolio. This plan contains a minimal 10
percent renewable energy target by 2020. AEP already plans to go beyond its initial commitment.
AEP has made significant progress in reducing a potent GHG — SF6 — which is found in some
electrical equipment. When AEP joined the Environmental Protection Agency’s (EPA) SF6 Emission
Reduction Partnership in 1999, our SF6 leakage rate was 10 percent. In 2008, this rate had been
reduced to 0.38 percent based on total system capacity, falling well below a self-imposed goal to
achieve a maximum 2.5 percent leak rate from 1996 levels. This was done by employing a
combination of technologies such as replacing SF6 insulated circuit breakers on lines to lower leakage
rates.
2.2.3.2 Post-2010 Plan For Voluntary Reductions
AEP’s post-2010 strategy is to voluntarily reduce or offset an additional 5 million tons of CO2
per year by purchasing offsets from projects such as forestry, reducing methane from agriculture,
adding more renewable energy in our portfolio and improving the efficiency of our power plants. The
investments AEP has made in its coal-fired power plants make them more efficient than the national
average for coal plants. Between 2001 and 2007, these improvements helped us to avoid burning 16.2
million tons of coal, preventing the release of 39 million tons of CO2.
AEP has signed contracts to add 903 MW of wind capacity in the past two years — about 90
percent of our original goal toward adding 1,000 MW of wind by 2011. In light of the increasing
number of state mandates and potential federal legislation, as well as the upcoming expiration of the
PTC, AEP will double this goal and add a total of 2,000 MW of renewable energy by the end of 2011,
with regulatory support. This will help us to further diversify our fuel portfolio. This integrated
resource plan contains a 10 percent renewable energy target by 2020.
As discussed in the following section, additional actions, including a future carbon capture and
storage program, will also help offset the anticipated growth in AEP’s carbon footprint.
2.2.3.3 The Role of Technology
Throughout its 100-year history, AEP has led the industry in advancing technology. The time is
right, with climate legislation on the horizon, to advance carbon capture technology to a commercial
scale. In March 2007 AEP signed agreements with world-renowned technology providers for carbon
AEP-SPP 2009 Integrated Resource Plan
11
capture and storage. A “product validation facility” is being constructed at the Mountaineer Plant in
West Virginia.
The Mountaineer project will employ Alstom’s chilled ammonia carbon capture technology
(Exhibit 2-4). Laboratory testing has shown that this process could capture more than 90 percent of
CO2 at a lower cost than other technologies that could be retrofitted at pulverized coal power plants.
A vendor-sponsored project demonstrating the technology was successfully completed on a 1.7 MW
(electric) slipstream at Pleasant Prairie a Wisconsin plant in 2008. This projected operated around the
clock for over 4,600 hours capturing 88 – 90 percent of CO2 emissions, and achieved purity levels
exceeding 99 percent.
Exhibit 2-4: CO2 Capture and Sequestration Process
Source: 2007AEP Corporate Responsibility Report
The chilled ammonia technology equipment is now being installed on AEP’s 1,300-MW
Mountaineer Plant as a 20MW (electric) product validation in the second half of 2009. It is designed
to capture approximately 100,000 metric tons of CO2 per year over a four to five year period, which
will be stored in deep geologic reservoirs. Battelle Memorial Institute is serving as AEP’s consultant
on geological storage. Following the completion of commercial verification AEP plans to scale up
the Mountaineer Chilled Ammonia Process (CAP) to capture CO2 from a 235 MWe slip stream.
AEP is seeking funding from the U.S. Department of Energy to then further scale up the Mountaineer
CAP to capture carbon dioxide from the entire flue gas stream. The expectation is for the commercial
scale technology to have a 90% capture rate of approximately 1.5 million tons of CO2 per year.
A second carbon capture technology AEP considered involves oxy-coal combustion. This
technology uses pure oxygen for the combustion of coal. Current generation technologies use air,
which contains nitrogen that is not used in the combustion process and is emitted with the flue gas.
By eliminating the nitrogen, this process leaves a flue gas that is a relatively pure stream of CO2 that
is ready for storage. At commercial scale, the CO2 likely would be stored in deep geologic
formations.
AEP-SPP 2009 Integrated Resource Plan
12
AEP’s vendor B&W completed a pilot demonstration and retrofit feasibility study in 2nd
Quarter 2008. Unfortunately, this technology proved to be cost prohibitive for use on our sub-critical
coal fleet.
2.3 Role and Impact of Commodity Pricing on Planning
Note: This section includes excerpts from the “Long Term Price Forecast 2009-2030: Return to
Fundamentals, 2H-2008” prepared by AEPSC’s Strategic & Economic Analysis Group (SEA) and
issued February 2009). Price forecasts are included in the Confidential Supplement.
The internal process utilized by AEP-SEA for projecting fundamental commodity pricing
utilized in long-term resource planning is
a time-intensive and iterative process.
Many factors ultimately affect power
prices as shown in Exhibit 2-5.
These numerous layers are also
interdependent. For instance, oil prices
affect rail transportation costs, which
impact coal prices, which impact SO2,
NOX, and power prices. It is easy to see
how minor deviations in one commodity
can have a trickle-down effect to power
prices.
The fundamental price drivers in the
modeling performed for the entire eastern
interconnect, as well as PJM, are the
assumptions around fuel prices, new
capacity builds and retirement, and load
growth. In the near term, fuel prices and
load growth play the most important role.
2.3.1 Power Prices
In the short-term, wholesale electricity prices remain extremely volatile due to the uncertainty in
the economy, environmental policy, and commodity markets. As such, the short term Reference price
does not fully capture the most recent market signals – see Confidential Supplement for a revised
short term forecast. In general, the Reference forecast overestimates current market prices.
In the mid-term, the value of the forecast resides less in the ability to precisely predict the power
price and more in the ability to accurately capture the trends in the power market. Starting in the mid-term,
the Reference Case begins to deviate from the external forecasts due to a range of views on
environmental policy and commodity markets. In particular, resolution on greenhouse gas (GHG)
legislation is expected to result in a range of power market trends.
In the Reference Case, carbon policy (2015) is incorporated in the power price – see Exhibit 2-
6. To an average coal market, the Reference carbon policy could represent an immediate increase in
Exhibit 2-5: Power Price Layers
Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan
13
the power price. In addition, the Reference carbon policy disproportionately impacts coal markets on
and off peak power prices. For example, in SPP on-peak prices increase 28% compared to 32% in the
off-peak market over the same period.
Exhibit 2-6: SPP On-Peak Price Index
SPP On-Peak Power Prices Index 2009 $/MWh = 1.0
0.0
0.5
1.0
1.5
2.0
2.5
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Source: AEP Fundamental Analysis
2.3.2 Fuel
2.3.2.1 Natural Gas
United States natural gas supply and consumption is currently rather loosely balanced because
of the global recession, but the market is still vulnerable to price spikes resulting from weather or
supply disruptions. Prices in 2009, while still reflective of Hurricane Ike-related supply loss, will
decline through 2012 as domestic natural gas production reverses its traditional decline due to
heretofore unconventional exploitation plays (see Exhibit 2-7).
Beyond 2014, unconventional natural gas production, buoyed by technology advancements,
provide adequate supply to meet demand when given long-term price signals above finding and
production costs of approximately $5.00 - $6.00/MMBtu (in 2008 dollars). The factor that will most
likely shape the fundamentals of overall gas demand will be the growth of gas consumption for
electricity generation. Additionally, the Alaskan Pipeline, projected to be on line in 2023, will deliver
gas from the North Slope to the Chicago Citygate.
Exhibit 2-7: Natural Gas Price Index
Gas Price PEPL TX-OK Index (2H08 2009 $/mmBtu = 1.0)
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
PEPL TX-OK 2H08
Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan
14
2.3.2.2 Coal
Coal is a unique commodity that comes with many different specifications. Coal is traded over-the-
counter at relatively thin volumes. The majority of coal transactions are done through contracts
between sellers and buyers, which sometimes results in significant differences between coal spot
prices and contract prices. Because of the high percentage of transportation cost relative to total
delivered coal cost and the significant capital investment required for a boiler to switch from one type
of coal to another, Btu and/or SO2 spreads may not hold when comparing different types of coal. In
addition to coal quality, reliability of coal delivery is another factor to consider in coal pricing. The
forecast (Exhibit 2-8) represents coal prices under a contract of 2-5 years, rather than spot prices.
During 2008, both international and U.S. domestic coal markets were on a rollercoaster. In
January of 2008, the international coal supply chain was disrupted by coal mine region flooding in
Australia, severe winter storm in China, and power outages in South Africa. As a result of these
events, coal producers in Australia declared force majeure for their mines in the flooding region, the
Chinese government issued an order to suspend its coal exports, and South Africa reduced its coal
output and exports.
International coal markets reacted to the coal supply disruptions and pushed coal prices even
higher for both thermal and metallurgical coals. High coal prices in international markets created a
great opportunity for U.S. coal producers to gain higher profits by exporting coal to international
markets rather than selling it in domestic markets. The increase in U.S. coal exports drained U.S.
domestic coal supply, especially in the Appalachian region, because of its location advantage for coal
export and its high energy content.
Exhibit 2-8: PRB Coal Price Index
COAL PRB FOB Index 2H08 2009 $/ton = 1.0
0.0
0.5
1.0
1.5
2.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
PRB 8800 2H08
Source: AEP Fundamental Analysis
Now, the situation of supply shortage of metallurgical coal has reversed due to the global
economic downturn. Demand for steel has been reduced dramatically, and the international
metallurgical coal benchmark at Newcastle of Australia is expected to be around $130/metric ton.
This is much lower than the $300/metric ton peak in 2008. The U.S. metallurgical coal exports fell
and the metallurgical coal producers in Appalachia are cutting their production, in contrast to
production expansion in early and middle 2008. For example, Consol closed its Mine 84, citing low
metallurgical coal prices.
AEP-SPP 2009 Integrated Resource Plan
15
2.3.3 New Build Cost
The capital cost forecast trends for pulverized coal, integrated gasification combined cycle
(IGCC), and nuclear power plants show similar trends. Capital costs have increased significantly from
rising materials, equipment, and labor. However, costs have declined recently due to the credit crisis
and economic concerns. Demand has dropped as companies look to delay their project schedules or
cancel projects outright. Demand has also dropped from industries that share similar materials and
labor with the energy industry. These factors lead to a downward trend in forecasts in the near term.
Longer term shows a slight upward trend, as demand returns in future years.
Given the trend for natural gas units to be built due to the combination of low capital cost, short
time frame to build, environmental uncertainty, and relatively lower gas price projections, the cost of
a gas plant will be driven more on the physical supply chain constraints of constructing the plant
versus the variable cost of the plants as seen in the base load unit profile. Gas plants are unlikely to
follow the downward projection of steel prices.
Renewable capacity offers almost no variable cost and for some renewables, reasonable capital
cost. However, the reliability and the amount of land required for renewable is a concern. The
primary driver for renewable build will be the environmental policies and technical improvements to
lower the cost of renewable generation and the build out of transmission capacity to move the wind
energy to the load centers.
Wind power has also experienced recent high material and equipment costs, as well as a
sharp increase in demand. U.S. wind power projects have increased significantly in recent years.
Reduced material costs and slower future growth rates may lead to wind power cost forecasts trending
downward in the near term.
Solar power is still in its early stage for wide commercial applications for power generation.
It is not as prevalent commercially as other types. Near term solar forecasts will benefit from reduced
material costs. Longer term forecasts show additional benefits as the technology develops and solar
power enjoys a better economy of scale.
2.3.4 Load Growth
The most overriding short-term concern for the economy is the recession. The National Bureau
of Economic Research (NBER), the official arbiter of the timing of recessions, has stated that the
recession began in December 2007. NBER utilizes data beyond the classic real Gross Domestic
Product (GDP) to gauge the beginning and ending of recessions. As an aside, the common definition
of recession is two consecutive quarters of negative GDP growth. The current recession has been
lengthy when compared with previous post World War II recessions. The longest recessions in this
period were 16 months and it appears likely that this economic downturn will exceed this length.
2.3.5 Emissions
2.3.5.1 SO2, NOX, and Mercury (Hg)
Environmental policy is one of the most fluid and unstable factors impacting the accuracy of the
long-term forecast. Policy options range from the Business-As-Usual Case (government policy is
AEP-SPP 2009 Integrated Resource Plan
16
very unlikely to become less regulated) to an extremely restrictive option with the potential to
significantly alter how the country fuels its electricity consumption.
On February 8, 2008, the D.C. Court vacated the Clean Air Mercury Rule (CAMR) governing
the release of mercury emissions. Today, there are no uniform technology standards or market-based
programs for mercury in the states in which AEP operates, although some other states have
established mercury control programs. According to the Environmental Group, Federal action is
anticipated and could become effective in 2014 when a command-and-control policy could require all
coal units to install either a mercury-specific control technology such as Activated Carbon Injection
(ACI) or Flue Gas Desulphurization/Selective Catalytic Reduction (FGD/SCR) emissions control
equipment. For development of market scenarios, the 2H08 forecast limits the FGD/SCR
installations to projects currently under construction as a result of equipment economics and the
evolution in emission regulations.
There is also a strong possibility that a plant-by-plant standard will replace a mercury trading
system. If this is the case, a dispatch price would not be required, but additional controls such as
baghouses or ACI would be needed. This could have an impact on proposed retirement dates of older,
non-controlled units and ultimately the timing for new capacity. When new standards and
implementation timelines are known, our plan will be re-evaluated and adjusted accordingly.
On July 11, 2008, the D.C. Circuit Court invalidated the Clean Air Interstate Rule (CAIR), and
the rule has been remanded to EPA. Today, policy alternatives remain fluid. The AEP Environmental
Group expects the CAIR program to be replaced with a more restrictive policy. In particular, the
absence of any guidance from EPA, the Environmental Group has postulated a scenario in which SO2
and NOx emissions will be 10 percent below the CAIR Phase II limits (fully implemented by 2025)
and exclude an allowance bank to meet emission targets. In the 2H08 forecast, annual NOx emissions
require a $1,000/ton price signal to remain in compliance, while SO2 emissions require a significant
price signal and an allowance bank to meet emission targets (Exhibit 2-9). The consultant forecast
represents the uncertainty associated with a replacement to CAIR, where policy options range from a
command-and-control policy (CERA-Breakpoint) to an additional constraint applied to the current
policy. However, the cap-and-trade policies typically include an allowance bank to meet emission
targets.
AEP-SPP 2009 Integrated Resource Plan
17
Exhibit 2-9: SO2 Emission Price Index
Emissions SO2 Index 2H08 2009 $/ton = 1.0
0
5
10
15
20
25
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
SO2 2H08
Source: AEP Fundamental Analysis
2.3.5.2 CO2
The forecasting of future CO2 allowance prices is subject to considerable uncertainty as the
underlying assumptions are entirely predicated upon a yet to be defined federal climate policy.
Strategic Policy Analysis has developed three potential CO2 price forecasts for each of the cases
(Exhibit 2-10). These forecasts attempt to represent a range of potential policy outcomes and
resulting pricing to account for the uncertainty. The Abundance and Constrained Cases are based on
the realistic limits of U.S. climate policy given current political and economic realities, while the
Reference Case is a weighting of the high and low forecasts and represents the most likely price
trajectory. Note: As the political and economic situation changes so will the politically acceptable
pricing range and likely pricing trajectory.
Exhibit 2-10: CO2 Emission Price Index
CO Price Index, Reference Case 2015 $/metric tonne = 1.0
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Low CO2 Reference High CO2
Source: AEP Fundamental Analysis
The price forecasts were developed at the beginning of 2009 based on public analyses of two of
the most prominent pieces of comprehensive U.S. climate legislation; the “Low Carbon Economy Act
of 2007” introduced by Senators Bingaman and Specter and the “Climate Security Act of 2008”
AEP-SPP 2009 Integrated Resource Plan
18
introduced by Senators Lieberman and Warner. The Bingaman-Specter bill was widely supported by
industry for its moderate emission reduction timeline, while the Lieberman-Warner was praised by
environmentalists for its more aggressive emission reduction timeline. Thus, these bills represent
relative “bookends” for likely climate policy outcomes.
*******************End of 2H08 Fundamental Analysis excerpt***********************
2.4 Issues Summary
The increasing number of variables and their uncertainty has added to the complexity of
producing an integrated resource plan. No longer are the variables merely the cost to build the
generation, a forecast of what had traditionally been stable fuel prices and growth in demand over
time. Highly volatile fuel prices, and uncertainty surrounding the economy and environmental
legislation require that the process used to determine a resource plan is sufficiently flexible to
incorporate more subjective criteria. The introduction of a cap-and-trade system and high capital
construction costs weigh unfavorably on solid-fuel options, but conclusions must be metered with the
knowledge that there is a great deal of uncertainty.
One way of dealing with uncertainty is to hedge one’s bets. That is, if there exists the potential
for very expensive carbon legislation, one might favor a solution that minimizes carbon emissions,
even if that solution is not the least expensive. While there may not yet be a national RPS, procuring
or adding wind generation resources now will put a company ahead of the game if one does come to
pass. In this way, the company is trading future uncertainty for a known cost. Lastly, adding
diversity to the generating portfolio reduces the risk of the overall portfolio. That may not be the least
expensive option in a “base” (or most probable) case, but it minimizes exposure to adverse future
events and could reduce the ultimate cost of compliance if the resultant demand for renewable
resources continues to grow, outpacing the supplier resource base akin to past experience associated
with the “dash to gas”..
The long-term planning horizon is characterized by several primary variables. First and
foremost, the prospect of legislation that in some way regulates GHGs. Any system enacted will likely
result in:
 Ultimate development and implementation of CO2 capture and sequestration technologies
which, in the east where higher-quality bituminous coals are prevalent, could ultimately
favor current Integrated Gasification Combined Cycle (IGCC) design technology over
traditional Pulverized Coal (PC) plants.
 Implementation of Renewable Portfolio Standards, either at a state or, ultimately, a national
level.
 Efficiency improvements, both supply and demand side.
 A system for offsetting CO2 emissions.
 Potential for volatile natural gas pricing marked by the offsetting effects of both increased
supply and increased demand.
AEP-SPP 2009 Integrated Resource Plan
19
 Emissions allowance prices in light of the as yet unresolved CAIR and CAMR/mercury
requirements, assumptions directly affecting the economic viability of uncontrolled coal
generation.
Finally, the IRP process was complicated further by the economic slowdown that escalated in
late 2008, which resulted in very different near-term commodities forecasts. The 2H08 forecast was
completed prior to this economic slow down. However, after comparing the long-term commodities
forecasts used in this IRP (the 2H08 Forecast) to the subsequent long term forecast prepared in the
Spring of 2009 (1H09 Forecast) as shown in Exhibit 2-11 it was apparent that the effects of the revised pricing
estimates were negligible after 2013 and did not warrant a new resource evaluation.
AEP-SPP 2009 Integrated Resource Plan
20
Exhibit 2-11: 2H08 vs. 1H09 Commodities Comparison
SPP On-Peak Power Prices Index (2H08 2009 $/MWh = 1.0)
0.0
0.5
1.0
1.5
2.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
On-Peak 1H09 On-Peak 2H08
COAL PRB FOB Index (2H08 2009 $/ton = 1.0)
0.0
0.5
1.0
1.5
2.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
PRB 8800 1H09 PRB 8800 2H08
Gas Price PEPL TX-OK Index (2H08 2009 $/mmBtu = 1.0)
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
PEPL TX-OK 1H09 PEPL TX-OK 2H08
Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan
21
3.0 Implications of Industry Issues in this IRP Cycle
3.1 Demand Response/Energy Efficiency (DR/EE)
The AEP System (East and West/SPP zones) has adopted peak demand reduction and energy
efficiency goals which are 1,000 MW and 2,250 GWh, respectively by year-end 2012. Concurrently,
several states served by the AEP System have mandated levels of efficiency and demand reduction.
There also exists the possibility of federally mandated efficiency levels. While this IRP establishes a
method for obtaining an estimate of DR/EE that is reasonable to expect for the zone, as a whole; the
ratemaking process in the individual states will ultimately shape the amount and timing of DR/EE
investment. As those processes evolve and mature, the “order of magnitude” estimates can be refined
and replaced with definitive programs.
3.2 Renewables
Renewable Portfolio Standards and goals have been enacted in over one half of the states in the
U.S. Adoption of further RPS at the state level or the enactment of Federal carbon limitations or
RPS, will impose the need for adding more renewables and the potential expenditure of billions of
dollars.
Wind is currently one of the most viable large-scale renewable technologies (with incentives)
and has been added to utility portfolios mainly via long-term power purchase agreements. Recently,
many IOUs have begun to add renewable assets to their portfolios. The best sites in terms of wind
resource and transmission are rapidly being secured by developers. Further, while an extension of the
Federal Production Tax Credit (PTC) for wind projects - to the end of 2012 - was enacted in February
2009, it will probably not be extended further as the implementation of Federal carbon or RPS is
expected to make unnecessary the incentive provided by the PTC. Acquiring this renewable energy
and/or the associated Renewable Energy Credit (REC) or Carbon Offset now will likely limit the risk
of increased cost that comes with waiting for further legislative clarity in the AEP states.
In early 2007, AEP committed to the acquisition of energy from 1,000 MW (nameplate) of
additional wind generation projects by the end of 2010 via long-term purchase power agreements as
part of AEP’s comprehensive strategy to address greenhouse gas emissions. In light of progress in
meeting this commitment, the goal was expanded in early 2009 to 2,000 MW by the end of 2011.
SWEPCO is already receiving energy from one wind project with nameplate rating of 79.5 MW.
Additional contracts have been executed for PSO for an additional 198 MW to be placed in service by
December, 2009 which will result in a total of 591 MW or approximately 12 percent of PSO’s energy
needs being met with renewables. Exhibit 3-1 lays out the AEP-SPP zone’s renewable plan by
operating company to meet its share of this target.
As can be seen in Exhibit 3-1, PSO and SWEPCO have a greater contribution to the renewable
goal than the remaining AEP companies. This is due to wind being economically favored in states
like Oklahoma and Texas, particularly due to the higher wind profile. Wind is the primary source of
renewable energy in the AEP plan.
AEP-SPP 2009 Integrated Resource Plan
22
Exhibit 3-1: Renewable Energy Plan Through 2030
AEP SYSTEM
Solar Wind
Biomass
Rnwbl Solar Wind
Biomass
Rnwbl Solar Wind
Biomass
Rnwbl Solar Wind
Biomass
Rnwbl
Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent
(MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales
2009 0 393 0 9.4% 0 31 0 0.6% 0 424 0 5.0% - 4 99 - 1.3%
2010 0 393 0 9.0% 0 111 0 2.3% 0 503 0 5.6% 10 1 ,029 - 2.5%
2011 0 591 0 13.3% 0 211 0 4.3% 0 801 0 8.6% 13 2 ,027 1 0 4.5%
2012 0 591 0 12.8% 0 311 0 6.3% 0 901 0 9.5% 15 2 ,827 1 09 6.4%
2013 (b) 0 591 0 12.7% 0 461 0 9.3% 0 1,051 0 10.9% 29 3 ,477 2 35 8.0%
2014 0 591 0 12.6% 0 461 0 9.2% 0 1,051 0 10.9% 42 3 ,477 2 35 8.0%
2015 0 658 0 14.0% 0 494 0 9.8% 0 1,151 0 11.8% 56 3 ,577 3 85 8.8%
2016 0 658 0 13.9% 0 594 0 11.6% 0 1,251 0 12.7% 70 3 ,777 3 85 9.1%
2017 0 858 0 18.0% 0 594 9 11.7% 0 1,451 9 14.7% 83 3 ,977 3 94 9.6%
2018 0 858 0 17.9% 0 594 9 11.6% 0 1,451 9 14.6% 100 3 ,977 5 21 10.1%
2019 0 858 0 17.8% 0 594 9 11.4% 0 1,451 9 14.5% 118 3 ,977 6 50 10.5%
2020 0 1,058 0 21.8% 0 594 9 11.3% 0 1,651 9 16.3% 133 4 ,377 6 50 11.3%
2021 0 1,058 0 21.6% 0 694 9 12.9% 0 1,751 9 17.0% 168 4 ,627 7 77 12.2%
2022 0 1,058 0 21.4% 0 794 9 14.6% 0 1,851 9 17.9% 220 4 ,827 7 77 12.6%
2023 0 1,158 0 23.3% 0 794 9 14.4% 0 1,951 9 18.6% 220 5 ,027 9 04 13.3%
2024 0 1,158 0 23.1% 0 894 9 16.0% 0 2,051 9 19.4% 271 5 ,327 9 04 13.9%
2025 0 1,158 0 22.9% 0 994 9 17.4% 0 2,151 9 20.0% 271 5 ,527 9 04 14.1%
2026 17 1,258 0 24.8% 17 994 9 17.3% 35 2,251 9 20.8% 340 5 ,727 9 04 14.5%
2027 17 1,258 0 24.6% 17 1,094 9 18.8% 35 2,351 9 21.5% 340 5 ,927 1 ,032 15.2%
2028 35 1,258 0 24.5% 35 1,094 9 18.7% 69 2,351 9 21.4% 409 6 ,127 1 ,032 15.5%
2029 35 1,358 0 26.2% 35 1,194 9 20.0% 69 2,551 9 22.8% 409 6 ,327 1 ,032 15.7%
2030 56 1,358 0 26.0% 56 1,394 9 23.1% 112 2,751 9 24.4% 496 6,527 1,032 16.1%
(a) Data EXCLUDES:
o AEP-Texas Central Co. & AEP-Texas Northern Co... as current and potential future state/federal RPS would be applicable to LSEs only.
o Conventional (run-of-river) hydro energy as a renewable source as it has been excluded from certain state and proposed federal RPS criteria…
Should hydro be ultimately included, it would contribute roughly 1% to the AEP System target by 2020.
(b) 2012/2013 represent the initial years for Federal RPS/RES mandates as currently proposed by several draft bills before Congress. Further, 2013
would represent the initial year after the likely expiration of Production Tax Credits (PTC) for, particularly, wind resources. The notion being that
establishment of a Federal renewables standard would likely eliminate further extension of such PTC opportunities.
PSO SWEPCO AEP-SPP
AEP Sytem - SPP Zone
Potential Renewables Profile to Achieve a 7% System Target by 2013, 10% by 2020, and 15% by 2030 (a)
...as well as Known or Emerging State-Specific Mandates
2009 IRP
Source: AEP Resource Planning
3.3 Carbon Capture & Storage/Sequestration (CCS)
Utility applications of CCS technologies continue to be developed and tested, and as such are
not yet commercially available on a large scale. However, given the focus on the advancement and
associated cost reduction of such technologies, it is likely to become both available and cost-effective
at some point over the IRP’s longer-term planning horizon (through 2030). However, this is very
dependent on the type of federal climate legislation that is passed and the degree to which there is
financial support for CCS technology in such legislation. Assuming carbon capture and storage
becomes commercially viable weight must be given to the options that are most readily adaptable to
this technology
3.4 Emission Compliance
Emission compliance requirements have a major influence on the consideration of supply-side
resources for inclusion in the IRP because of their potential significant effects on both capital and
operational costs. The AEP System’s strategy for complying with Title IV of the Clean Air Act
Amendments of 1990, as well as recent regulations tied to environmental air emissions, takes into
consideration additional power plant emission reduction requirements for SO2, NOx, and mercury
(Hg) emissions.
Specifically, in 2005, the U.S. Environmental Protection Agency (USEPA) established new
emission regulations for these pollutants as part of the CAIR (which the D.C. Circuit Court
AEP-SPP 2009 Integrated Resource Plan
23
overturned on July 11, 2008), the now vacated Clean Air Mercury Rule (CAMR), and Clean Air
Visibility Rule (CAVR) rulemaking. Further, on-going debate over CO2/GHG emissions, particulate
matter (PM), and regional haze, as well as the previously mentioned potential enactment of additional
state and/or Federal RPS will likewise influence future capacity resource planning surrounding
decisions to retrofit, modify operations, or retire/mothball generating assets.
Certain PSO and SWEPCO coal and gas-fired generating units are subject to CAVR and
application of Best Available Retrofit Technology (BART) for SO2 and NOX. PSO will be equipping
its units with NOX combustion technology to meet BART limits for NOX and is expected to install
flue gas desulfurization technology (FGD) at the Northeastern 3 & 4 coal units to meet BART limits
for SO2 and PM. The specific timing of these installations is uncertain as the Oklahoma Department
of Environmental Quality is still developing its State Implementation Plan for the CAVR program.
SWEPCO plans to install FGD at Flint Creek station to meet CAVR.
AEP-SPP 2009 Integrated Resource Plan
24
AEP-SPP 2009 Integrated Resource Plan
25
4.0 Current Resources
The initial step in the IRP process is the demonstration of the region-specific capacity resource
requirements. This “needs” assessment must consider projections of:
 Existing capacity resources—current levels and anticipated changes
 Anticipated changes in capability due to efficiency and/or environmental retrofit projects
 Changes resulting from decisions surrounding unit disposition evaluations
 Regional and sub-regional capacity and transmission constraints/limitations
 Load and (peak) demand (see Section 5.2.)
 Current DR/EE (see Section 5.3.)
 SPP capacity reserve margin and reliability criteria (see Section 6.1.)
In addition to the establishment of the absolute annual capacity position, an additional “need” to
be discussed in this section will be a determination of the specific operational expectation (duty type)
of generating capacity–baseload vs. intermediate vs. peaking.
4.1 Existing PSO and SWEPCO Generating Resources
Appendix A offers a summary of all owned supply resources for the AEP-SPP zone plus long-term
wind contracts. The current (June 1, 2009) AEP-SPP summer supply of 9,216 MW is composed
of the following (with wind projects’ capacity at ratings allowed by SPP, generally about 8% of
nameplate):
Exhibit 4-1: Existing PSO and SWEPCO Generating Resources
PSO SWEPCO Total
Coal/Lignite 1,026 MW 2,680 MW 3,706 MW
Gas/Diesel 3,384 MW 2,086 MW 5,470 MW
Wind 17 MW -- 17 MW
Total 4,427 MW 4,766 MW 9,193 MW
Source: AEP Resource Planning
4.2 Capacity Impacts of Environmental Compliance Plan
As detailed in Exhibit 4-2 and Appendix D, the capability forecast of the existing generating
fleet reflects 27 MW in unit de-ratings associated with environmental retrofits - largely flue gas
desulphurization (FGD), and activated carbon injection with a baghouse (ACIBH) or with an
electrostatic precipitator (ACIESP) over the IRP period.
AEP-SPP 2009 Integrated Resource Plan
26
Exhibit 4-2: PSO and SWEPCO Capacity Change After June 2009
Unit and Cause Year (a) Capacity Impact Year (a) Capacity Impact
Welsh 2 (FGD) 2013 -8 2015 -8
Flint Creek 1 (FGD) 2014 -4 2014 -4
Pirkey 1 (ACIESP) 2014 0 -- --
Dolet Hills 1 (ACIESP) 2014 0 -- --
Flint Creek 1 (ACIESP) 2014 0 -- --
Welsh 1 (ACIBH) 2014 -11 -- --
Welsh 2 (ACIESP) 2014 0 -- --
Welsh 3 (ACIBH) 2014 -11 -- --
Northeastern 3 (FGD + ACIESP) 2014 -7 2016 -7
Northeastern 4 (FGD + ACIESP) 2014 -8 2016 -8
Oklaunion 1 (ACIESP) 2014 0 -- --
Net Change -49 -27
Note : (a) Summer season of effective SPP delivery year.
As Modeled In Final Plan
AEP West Capacity Changes (MW) after June 1, 2009
Source: AEP Resource Planning
4.3 Existing Unit Disposition
A long-term view of disposition alternatives facing older units in the AEP-SPP region was
established. The work group affirmed the findings of previous studies, recommending no unit
disposition planned for the IRP period. In general, the capacity value provided by the older units far
outweigh the fixed costs associated with their continued operations, The work group report is include
in the technical addendum.
4.4 AEP-SPP Transmission
4.4.1 Transmission System Overview
The western Transmission System, which consists of the transmission facilities of the four
western AEP operating companies, is operated in both the SPP and ERCOT. The western
Transmission System spans portions of four states and comprises nearly 10,000 miles of circuitry
operating at or above 69 kV.
The portion of the western Transmission System operating in SPP (AEP-SPP zone) consists of
approximately 1,270 miles of 345 kV, approximately 3,400 miles of 138 kV, and 2,197 miles of 69
kV. The AEP-SPP zone is also integrated with and directly connected to ten other companies at 87
interconnection points, of which 69 are at or above 69 kV and to ERCOT via two high voltage direct
current (HVDC) ties. These interconnections provide an electric pathway to provide access to off-system
resources, as well as a delivery mechanism to neighboring systems.
4.4.2 Current AEP-SPP Transmission System Issues
Historically, the AEP SPP Transmission System was planned to deliver operating company
generation to their respective loads, as well as to provide interconnections with neighboring utilities
AEP-SPP 2009 Integrated Resource Plan
27
for replacement and emergency power exchanges when needed and available. With the creation of
the SPP Regional Transmission Organization (RTO), the system is primarily planned under the
current SPP Transmission Expansion Plan (STEP) annual process for reliability and transmission
owner projects. The STEP process also identifies transmission reliability improvements to
accommodate approved transmission service and approved economic upgrades on an annual basis
looking out over a ten year period. SPP RTO’s process addresses transmission service needs to
deliver energy to loads and generation interconnection requests in separate studies. Going forward,
the SPP RTO will be using an Integrated Transmission Planning (ITP) process that is being
developed.
The limited capacity of interconnections between SPP and neighboring systems, as well as the
electrical topology of the SPP footprint transmission system, influences the ability to deliver non-affiliate
generation, both within and external to the SPP footprint, to AEP-SPP loads and from
sources within AEP-SPP balancing authority to serve AEP-SPP loads. Moreover, a lack of seams
agreements between SPP and its neighbors has significantly slowed down the process of developing
new interconnections. Despite the robust nature of the AEP-SPP transmission system as originally
designed, its current use is in a different manner than originally designed, in order to meet SPP RTO
requirements, which can stress the system. In addition, factors such as outages, extreme weather, and
power transfers also stresses the system. This has resulted in a transmission system in the AEP-SPP
zone that is constrained when generation is dispatched in a manner inconsistent with the original
design of utilizing local generation to serve local load. The resulting use of the AEP-SPP system is
inconsistent with the assumptions used to develop the models AEP provides to SPP to develop and
plan the system. SPP uses models provided by all load serving entities to study the reliability needs
of the SPP footprint. As discussed above, SPP currently uses separate modeling and studies to
address transmission service and interconnection requests.
4.4.2.1 The SPP Transmission Planning Process
Currently, SPP produces an annual SPP transmission expansion plan (STEP) that includes a ten
year system forecast. The STEP is developed through an open stakeholder process with AEP
participation. SPP studies the transmission system, checking for base case and contingency overload
and voltage violations in all of the SPP base case load flow models, plus models which include power
transfers biased in the various transfer directions.
The 2008 STEP summarizes 2008 activities, including expansion planning and long-term SPP
Open Access Transmission Tariff studies (Tariff Studies) that impact future development of the SPP
transmission grid. Six key topics are included in the STEP:
1) Tariff Studies,
2) Regional reliability assessment 2009-2018,
3) Subregional and local area planning,
4) High priority economic studies,
5) Interregional coordination; and
6) Project tracking.
AEP-SPP 2009 Integrated Resource Plan
28
These topics are critical to meeting mandates of either the SPP strategic plan or the nine
planning principles in FERC Order 890. As a RTO under the domain of the Federal Energy
Regulatory Commission (FERC), SPP must meet requirements of FERC and the SPP Open Access
Transmission Tariff (OATT or Tariff). The SPP RTO acts independently of any single market
participant or class of participants. It has sufficient scope and configuration to maintain electric
reliability, effectively perform its functions, and support efficient and non-discriminatory power
markets. Regarding short-term reliability, the SPP RTO has the capability and exclusive authority to
receive, confirm, and implement all interchange schedules. It also has operational authority for all
transmission facilities under its control. The 10-year RTO regional reliability assessment continues to
be a primary focus.
STEP projects are categorized by the following designations:
 Economic: Projects identified for economic benefit;
 Generation Interconnect – Projects associated with a FERC-filed Interconnection
Agreement;
 Interregional- Projects developed with neighboring Transmission Providers;
 Regional reliability - Base Plan projects needed to meet the reliability of the region;
 Transmission service – Projects associated with a FERC-filed Service Agreement; and
 Zonal Reliability - Projects identified to meet more stringent local Transmission Owner
criteria.
The 2008 STEP identified approximately $2.7 billion of transmission Network Upgrades.
These include Network Upgrades required for NERC Reliability Standards or SPP Criteria; Zonal
Reliability Upgrades (compliance to Transmission Owner company-specific planning criteria);
requests for transmission service under the Tariff with a FERC-filed Service Agreement; and
generation interconnections with a FERC-filed interconnection agreement.
In addition, the SPP Regional State Committee and SPP Board of Directors/Members
Committee approved a long-awaited group of extra high voltage economic transmission expansion
upgrade projects totaling over $700 million, to be funded by FERC-approved "postage stamp" rates,
applicable to SPP's transmission-owning members across the region. The adjusted production cost
benefits of this group of transmission upgrades have been demonstrated by model analysis to
outweigh the costs (benefits greater than costs), thus achieving a "balanced portfolio" of projects. A
portfolio approach alleviates potential disputes that may arise from the construction of a single project
that may benefit one zone but not others. The balanced portfolio includes five new 345 kV
transmission lines, a 345 kV transformer, and a new connection between two existing 345 kV lines.
Details of the balanced portfolio results can be found at:
http://www.spp.org/publications/2009%20Balanced%20Portfolio%20-%20Final%20Approved%20Report.pdf
The SPP Board of Directors also recently approved a new report, prepared by the Synergistic
Planning Project Team that recommends restructuring the organization's regional planning processes
to focus on the construction of a robust transmission system, large enough in both scale and
geography to provide flexibility to meet SPP's future needs. The new Integrated Transmission
AEP-SPP 2009 Integrated Resource Plan
29
Planning (ITP) process is intended to integrate or replace the STEP, balanced portfolio, and the Extra-
High Voltage Overlay process.
4.4.2.2 PSO-SWEPCO Interchange Capability
Operational experience and internal assessments of company transmission capabilities indicate
that, when considering a single contingency outage event, the present firm capability transfer limit
from PSO to SWEPCO is about 200 MW, and from SWEPCO to PSO is about 900 MW. As much as
900 MW may be available bi-directionally for economical energy transfers when no transmission
facilities are out of service. However, the intra-company available transmission capability between
the two companies is available to all transmission users under the provisions established by FERC
Order 888 and subsequent orders. Thus, there is some question as to whether, in the future, as SPP
grants further transmission rights, any transfer capability will in fact be available without further
upgrades to the transmission system.
Increasing the firm transfer capability from PSO to SWEPCO beyond about 200 MW may not
be cost-effective. As previously indicated each, company’s capacity additions are planned so that
each meets its own reserve requirement over the long-term. Any capacity transfers (i.e. “reserve
sharing”) should be considered for short time frames only. Specifically, the practice has been that, as
the last step of the planning process, the respective PSO and SWEPCO expansion plans are adjusted
to take advantage of any surplus of one company that might match a potential deficit of the other, and
thereby delay some of the identified new capacity. Because of the sizes, demand growth rates, and
peak coincidence of the two companies, it rarely appears that either company would ever have more
than 200 MW of surplus capacity in any year that could be transferred to the other company.
4.4.2.3 AEP-SPP Import Capability
Currently the transmission system cannot accommodate incremental firm imports to the AEP-SPP
area, based on preliminary AEP studies. Generally, the transfers are limited by the facilities of
neighboring systems rather than by transmission lines or equipment owned by AEP.
Increasing the import capabilities with AEP-SPP’s neighboring companies could require a large
capital investment for new transmission facilities by the neighboring systems or through sponsored
upgrades by SPP transmission owners. An analysis of the cost of the upgrades cannot be performed
until the capacity resources are determined. For identified resources, the cost of any transmission
upgrades necessary on AEP’s transmission system can be estimated by AEP once SPP has identified
the upgrade. AEP’s Southwest Transmission Planning group can identify constraints on third-party
systems through ad hoc power flow modeling studies, but Southwest Transmission Planning does not
have information to provide estimates of the costs to alleviate those third-party constraints.
4.4.2.4 SPP Studies that may Provide Import Capability
Besides the annual STEP process, SPP also performs other special studies or area studies on an
as needed basis. Two recent SPP studies could in time lead to improved transfer capability between
AEP-SPP and neighboring companies and regions.
AEP-SPP 2009 Integrated Resource Plan
30
4.4.2.4.1 EHV Overlay Study
SPP hired a consultant, Quanta, to determine if SPP should build a 345, 500 or 765 kV overlay
to the existing SPP footprint. As of May 2008, the most recent version of this EHV Overlay Study
included plans for construction of a 765 kV transmission system across much of SPP that would
accommodate 13.5 GW of wind generation resources. One 765 kV loop would encompass much of
the Texas Panhandle and portions of western Oklahoma. Another 765 kV loop would encompass
much of the Oklahoma Panhandle and southwestern Kansas. These loops could be used to connect
large amounts of potential wind generation and wind generation in the generation interconnection
queue to the transmission grid. From these loops, two 765 kV paths would be extended, one to
Lawton and Muskogee, Oklahoma, and then northward toward the Kansas City area; the other to
Wichita, Kansas and eastward toward the Kansas City area. The 765 kV system would also extend
eastward with two 765 kV lines, one to the southeast to Entergy and one to the northeast to
Associated Electric Cooperative, Inc. (AECI). The plan also includes a new 500 kV line extending
eastward from Oklahoma Gas and Electric’s (OG&E) Fort Smith Station across central Arkansas to
Entergy, a large amount of 345 kV in northwestern Arkansas and southwestern Missouri, and five 345
kV lines in Kansas and Oklahoma. The total cost to implement the plan is approximately $8 billion.
The future of the overlay is uncertain. SPP performed an economic analysis of the original overlay
study. However, routing changes to the original projects have been proposed since the inclusion of
the Nebraska entities into SPP and the study is not yet completely vetted among stakeholders. From
an AEP perspective, the proposed overlays in the various study versions would enhance bulk power
transfers among the involved regions, but it is not known what additional, local facilities would be
required to create increased import capability. The SPP Board of Directors has yet to approve an
overlay plan but is now looking at a new synergistic integrated transmission planning process that
may incorporate the results of the study.
4.4.2.4.2 Ozark Transmission Study
This study, completed by SPP in June 2007, provides a long-range plan for the northern
Arkansas and southern Missouri region and provides guidance for future reinforcements to the
transmission system in this area. The recommendations include 500 kV lines from Entergy’s
Arkansas Nuclear One Station to OG&E’s VBI Station to AEP’s South Fayetteville Station. The
recommendations also included a 345 kV loop around the Fayetteville / Springdale area of
northwestern Arkansas as well as 345 kV expansion eastward to SWPA’s Table Rock Station located
in southwestern Missouri. From Table Rock Station, 345 kV lines to AECI’s Gobbler Knob Station
in southeastern Missouri and City Utilities of Springfield’s Brookline Station in southwestern
Missouri were also recommended. AEP and Arkansas Electric Cooperative Corporation (AECC)
have asked SPP to further study the 345 kV loop around the south side of the Fayetteville / Springdale
area as a complex priority project.
4.4.3 Recent AEP-SPP Bulk Transmission Improvements
Over the past several years, there have been several major transmission enhancements initiated
to reinforce the AEP-SPP transmission system. These enhancements include:
AEP-SPP 2009 Integrated Resource Plan
31
 Northwest Arkansas— Northwest Arkansas is one of the fastest growing areas on the
AEP-SPP Transmission System. The approximate 1,200 MW of load in this area, about
47% of which is AECC retail load, is supplied primarily by the SWEPCO and AECC
jointly-owned Flint Creek generating plant, the SWEPCO Mattison generating plant, the
GRDA-Flint Creek 345 kV line, and the Clarksville-Chambers Spring 345 kV line. Wal-
Mart’s international headquarters and its supplying businesses’ offices and Tyson’s
headquarters are all located in this area. A significant conversion of the 69 kV transmission
system to 161 kV and extensive rebuilding and upgrading of portions of the existing 161 kV
system have been completed in recent years. In May 2008, the conversion of the 69 kV line
between Dyess and South Fayetteville stations to 161 kV and the construction of a new 345
kV line between Chambers Spring and Tontitown stations were completed. In May 2009, a
rebuild and reconductoring of the Flint Creek-Motley Road 161 kV line section was also
completed.
 Port of Shreveport (Port), Louisiana— A 138 kV loop is under construction, in phases,
around the Port to increase system reliability and to serve the increasing area load. In May
2008, a six -mile 138 kV transmission line was completed from Wallace Lake Station to
Port Robson Station to supply new loads under development at the Port. The 138 kV loop
has been extended from Port Robson Station to Bean Station and was further extended to
Caplis Station in June 2009. A 138 kV line approximately 23 miles long, connecting Caplis
Station to Red Point Station is also planned to complete the 138 kV loop. Together, these
improvements will supply power to the Port and the new distribution station site near
Caplis; correct contingency low voltage and thermal overloads in Bossier City, Louisiana
and the vicinity; and supply a second feed to Bean, Caplis, McDade, and Haughton stations.
This loop is currently expected to be completed in 2012.
 Shreveport line upgrades for Stall Plant generation addition – Several 138 kV and 69
kV lines in Shreveport, Louisiana have been or are being upgraded to accommodate the
Stall generation unit that is to be added at the Arsenal Hill Power Plant.
4.4.4 Impacts of New Generation:
There has been significant growth of approximately 5,700 MW of merchant generation in the
AEP-SPP zone. The total generation connected to the AEP-SPP Transmission System, including
electric cooperative generation, is approximately 15,600 MW. Integration of additional generation
capacity within the AEP-SPP zone will likely require significant transmission upgrades. At most
locations, any additional generation resources will aggravate existing transmission constraints.
Specifically:
 Western Oklahoma/Texas Panhandle—there are very few EHV transmission lines in this
area. In fact, transmission facilities above 69 kV are limited. However, the area is one of
the highest wind density areas within the SPP RTO footprint. The potential wind farm
capacity for this area has been estimated to exceed 4,000 MW. Several wind farms have
already been built, and several more are in the development stages. Wind generation
additions in the SPP footprint in this region will likely require significant transmission
AEP-SPP 2009 Integrated Resource Plan
32
enhancements, including EHV line and station construction, to address thermal, voltage, and
stability constraints.
 PSO/SWEPCO Interface - There is one 345 kV EHV line linking PSO’s service area with
the majority of SWEPCO’s generation resources in its service area. Until recently,
constraints on the underlying transmission system limited the amount of firm generation that
can flow from PSO to SWEPCO and from SWEPCO to PSO to approximately zero in a
single contingency situation. However, an SPP approved project to rebuild the Danville to
North Magazine 161 kV line will increase the transfer capability from SWEPCO to PSO to
approximately 900 MW when completed in the Summer of 2009. Also, an SPP approved
project to rebuild the Broken Bow to Craig Junction 138 kV line has been completed and
has increased the transfer capability from PSO to SWEPCO to approximately 200 MW.
Significant generation additions to the AEP-SPP transmission facilities (or connection to
neighbor’s facilities) may require significant transmission enhancements, possibly including
EHV line and station construction, to address thermal, voltage, and stability constraints.
 Tulsa Metro Area—the Tulsa metro area load is supplied primarily by the PSO
Northeastern, Riverside, and Tulsa Power Station generating plants. Additionally,
Oklahoma Gas & Electric Company has large generation plants located to the southeast and
southwest of Tulsa, and there are large merchant plants just east and south of Tulsa. The
Grand River Dam Authority has a large plant located to the east of Tulsa. Generation
additions in the Tulsa area would likely require significant enhancements in the EHV and
sub-transmission system to address thermal, voltage and stability constraints.
 SPP Eastern Interface—there are only five east-west EHV lines into the SPP region,
which stretches from the Gulf of Mexico (east of Houston) north to Des Moines, Iowa. This
limitation constrains the amount of imports and exports along the eastern interface of SPP
with neighboring regions. It also constrains the amount of transfers from the capacity rich
western SPP region to the market hubs east and north of the SPP RTO region. Significant
generation additions near or along the SPP eastern interface would likely require significant
transmission enhancements, including EHV line and station construction, to address thermal
and stability constraints should such generation additions adversely impact existing
transactions along the interface. SPP has addressed some of these potential ties in the EHV
Overlay Study discussed above.
Integration of generation resources at any location within the AEP-SPP zone will require
significant analysis by SPP to identify potential thermal, short circuit, and stability constraints
resulting from the addition of generation. Depending on the specific location, EHV line and station
construction, in addition to connection facilities, could be necessary. Other station enhancements,
including transformer additions and breaker replacements may be necessary. Some of the required
transmission upgrades could be reduced or increased in scope if existing generating capacity is retired
concurrent with the addition of new capacity.
4.4.5 Horizon Transmission LLC, Joint Venture in the SPP
On July 15, 2008, Electric Transmission America (ETA), a joint venture of American Electric
Power and MidAmerican Energy Holdings, formed a joint venture company with OGE Energy Corp.
AEP-SPP 2009 Integrated Resource Plan
33
to build and own new electric transmission assets

2009 AEP-SPP
(Public Service Company of Oklahoma & Southwestern Electric Power Company)
INTEGRATED RESOURCE PLAN
2010-2019
Date Issued: July 2009
Business Confidential
Copy Control # ______
AEP-SPP 2009 Integrated Resource Plan
The Integrated Resource Plan (IRP) is based upon the best available
information at the time of preparation. However, changes that may impact this
plan can, and do, occur without notice. Therefore this plan is not a
commitment to a specific course of action, since the future, now more than
ever before, is highly uncertain, particularly in light of the current economic
conditions, access to capital, the movement towards increasing use of
renewable generation and end-use efficiency, as well as legislative proposals to
control “greenhouse gases.”
The implementation action items as described herein are subject to change as
new information becomes available or as circumstances warrant. It is AEP’s
intention to revisit and refresh the IRP annually.
.
The contents of this report contain the Company’s forward-looking projections and recommendations
concerning the capacity resource profile of its affiliated operating companies located in the Southwest
Power Pool (SPP) Regional Transmission Organization. This report contains information that may be
viewed by the public. Business sensitive information has been excluded from this document, but will
be made available in a confidential supplement on an as needed basis to third parties subject to
execution of a confidentiality agreement. The confidential supplement should be considered strictly
business sensitive and proprietary and should not be duplicated or transmitted in any manner. Any
questions or requests for additional copies of this document should be directed to:
Scott C. Weaver
Managing Director—Resource Planning and Operational Analysis
Corporate Planning & Budgeting
(614) 716-1373 (audinet: 200-1373)
scweaver@aep.com
AEP-SPP 2009 Integrated Resource Plan
AEP-SPP 2009 Integrated Resource Plan
Table of Contents
Executive Summary................................................................................................................. i
1.0 Introduction...................................................................................................................... 1
1.1 IRP Process Overview ................................................................................................................. 1
1.2 Introduction to AEP ..................................................................................................................... 1
2.0 Current Resource Planning Issues in the Electric Utility Industry ............................. 7
2.1 Regulation/Deregulation .............................................................................................................. 7
2.2 Climate Change and Greenhouse Gases.......................................................................................7
2.3 Role and Impact of Commodity Pricing on Planning ................................................................ 12
2.4 Issues Summary ......................................................................................................................... 18
3.0 Implications of Industry Issues in this IRP Cycle........................................................ 21
3.1 Demand Response/Energy Efficiency (DR/EE) ........................................................................ 21
3.2 Renewables ............................................................................................................................... 21
3.3 Carbon Capture & Storage/Sequestration (CCS) ....................................................................... 22
3.4 Emission Compliance ................................................................................................................ 22
4.0 Current Resources .......................................................................................................... 25
4.1 Existing PSO and SWEPCO Generating Resources .................................................................. 25
4.2 Capacity Impacts of Environmental Compliance Plan .............................................................. 25
4.3 Existing Unit Disposition........................................................................................................... 26
4.4 AEP-SPP Transmission.............................................................................................................. 26
5.0 Demand Projections........................................................................................................ 35
5.1 Load and Demand Forecast - Process Overview ....................................................................... 35
5.2 Peak Demand Forecast............................................................................................................... 36
5.3 Current DR/EE Programs........................................................................................................... 38
6.0 Capacity Needs Assessment ........................................................................................... 41
6.1 RTO Requirements .................................................................................................................... 42
6.2 Capacity Positions—Historical Perspective............................................................................... 43
7.0 Planning Objectives ........................................................................................................ 45
7.1 Planning Flexibility—Covering Capacity Deficient Positions with Market Opportunities....... 45
7.2 Planning Horizon ....................................................................................................................... 45
7.3 Establishing the Optimal Asset “Mix”....................................................................................... 45
7.4 Other Operational Factors .......................................................................................................... 45
7.5 Affordability.............................................................................................................................. 46
8.0 Resource Options ............................................................................................................ 47
8.1 Market Options and “Build vs. Buy” Considerations ................................................................ 47
8.2 Traditional Capacity-Build Options........................................................................................... 49
8.3 Renewable Alternatives ............................................................................................................. 54
8.4 Carbon Capture .......................................................................................................................... 61
8.5 Demand Side Alternatives.......................................................................................................... 62
9.0 Evaluating DR/EE Impacts for the 2009 IRP .............................................................. 67
9.1 gridSMARTSM........................................................................................................................... 67
9.2 Demand Response/Energy Efficiency Mandates and Goals ...................................................... 67
9.3 Assessment of Achievable Potential .......................................................................................... 68
9.4 Determining Programs for the IRP ............................................................................................ 69
9.5 Optimizing the Incremental DR/EE Resources.......................................................................... 71
9.6 Discussion and Conclusion ........................................................................................................ 74
10.0 Fundamental Modeling Parameters............................................................................ 77
AEP-SPP 2009 Integrated Resource Plan
10.1 Modeling and Planning Process—An Overview..................................................................... 77
10.2 Methodology........................................................................................................................... 77
10.3 Key Fundamental Modeling Input Parameters ........................................................................ 78
11.0 Resource Portfolio Modeling ....................................................................................... 81
11.1 The Strategist Model—An Overview...................................................................................... 81
11.2 Strategist Optimization............................................................................................................ 83
11.3 AEP–SPP Supply-side Resource “Type” Options/Characteristics.......................................... 83
11.4 AEP-SPP DR/EE and Renewable Resource Options/Characteristics ..................................... 84
11.5 PSO Plan Development ........................................................................................................... 85
11.6 SWEPCO Plan Development .................................................................................................. 97
12.0 Risk Analysis ............................................................................................................... 107
12.1 The URSA Model.................................................................................................................. 107
12.2 URSA Modeling Results ....................................................................................................... 108
12.3 Capital Cost Risk Assessment ............................................................................................... 111
12.4 Results Including Capital Cost Risk ...................................................................................... 111
12.5 Conclusion From Risk Modeling........................................................................................... 114
13.0 Conclusions and Recommendations.......................................................................... 115
13.1 Capacity and Energy Plan...................................................................................................... 115
13.2 Comparison to 2008 IRP ....................................................................................................... 121
13.3 Plan Impact on Carbon Mitigation (“Prism” Analysis) ......................................................... 121
13.4 Arkansas Stakeholder Process - SWEPCO............................................................................ 124
13.5 Conclusion............................................................................................................................ 125
14.0 Implementation ........................................................................................................... 127
14.1 Current Commitments ........................................................................................................... 127
AEP-SPP 2009 Integrated Resource Plan
Exhibits
Exhibit 1-1: IRP Process Overview.......................................................................................................................2
Exhibit 1-2: AEP System, East and West Zones ....................................................................................................3
Exhibit 1-3: PSO Reserve Margin With and Without Exelon PPA........................................................................4
Exhibit 1-4: SWEPCO Reserve Margin With and Without Turk and Stall Plants .................................................4
Exhibit 2-1: Fossil Fuel-to-Electricity Emissions, by Fuel Type ...........................................................................7
Exhibit 2-2: CO2 Price Forecast .............................................................................................................................8
Exhibit 2-3: Renewable Standards by State ...........................................................................................................9
Exhibit 2-4: CO2 Capture and Sequestration Process...........................................................................................11
Exhibit 2-5: Power Price Layers..........................................................................................................................12
Exhibit 2-6: SPP On-Peak Price Index.................................................................................................................13
Exhibit 2-7: Natural Gas Price Index ...................................................................................................................13
Exhibit 2-8: PRB Coal Price Index ......................................................................................................................14
Exhibit 2-9: SO2 Emission Price Index ................................................................................................................17
Exhibit 2-10: CO2 Emission Price Index..............................................................................................................17
Exhibit 2-11: 2H08 vs. 1H09 Commodities Comparison.....................................................................................20
Exhibit 3-1: Renewable Energy Plan Through 2030............................................................................................22
Exhibit 4-1: Existing PSO and SWEPCO Generating Resources ........................................................................25
Exhibit 4-2: PSO and SWEPCO Capacity Change After June 2009....................................................................26
Exhibit 5-1: Load and Demand Forecast Process—Sequential Steps ..................................................................35
Exhibit 5-2: AEP-SPP Peak Demand and Energy Projection...............................................................................37
Exhibit 5-3: AEP-SPP Current DR/EE Programs full-year impacts ....................................................................40
Exhibit 6-1: Capacity vs. SPP Minimum Required Reserves...............................................................................41
Exhibit 6-2: Summary of Capacity Deficiency Position ......................................................................................42
Exhibit 6-3: AEP-SPP, Historical Capacity Position ...........................................................................................43
Exhibit 8-1: Projected SPP Capacity Margin ......................................................................................................47
Exhibit 8-2: Recent Merchant Generation Purchases ...........................................................................................48
Exhibit 8-3: United States Wind Power Locations...............................................................................................56
Exhibit 8-4: United States Solar Resource Locations...........................................................................................57
Exhibit 8-5: Land Area Required to Support Biomass Facility ............................................................................58
Exhibit 8-6: Biomass Resources in the United States...........................................................................................59
Exhibit 8-7: Renewable Sources Included in AEP-SPP and East 2009 IRP ........................................................60
Exhibit 8-8: Typical DR/EE Measure Conservation Load Factor........................................................................65
Exhibit 9-1: Impact of Legislation on Energy Consumption................................................................................67
Exhibit 9-2: Achievable Versus Technical Potential (Illustrative) .......................................................................68
Exhibit 9-3: AEP-SPP Zone Cost Effectiveness of Relative Programs................................................................70
Exhibit 9-4: AEP-SPP Zone DR/EE Proxy Blocks ..............................................................................................71
Exhibit 9-5: AEP-SPP Zone DR/EE Modeling Constraints .................................................................................72
Exhibit 9-6: AEP-SPP Zone DR/EE Blocks Selected in Resource Modeling (AEP-SPP)...................................73
Exhibit 9-7: AEP-SPP Internal EE Target versus IRP .........................................................................................74
Exhibit 9-8: AEP-SPP Zone DR/EE Assumption Summary ................................................................................75
Exhibit 10-1: Long-term Forecast Process Flow..................................................................................................78
Exhibit 10-2: Input Scenarios and Sensitivities....................................................................................................79
Exhibit 11-1: AEP Sponsored DSM Programs.....................................................................................................85
Exhibit 11-2: Comparison of PSO Optimal and Suboptimal Plans ......................................................................86
Exhibit 11-3: PSO Optimal Plan Comparison for Power and CO2 Price Scenarios .............................................87
Exhibit 11-4: PSO Full Study Period Revenue Requirements .............................................................................88
Exhibit 11-5: PSO Full Study Period Cost over Optimal Plan .............................................................................88
Exhibit 11-6: PSO Plan Comparisons ..................................................................................................................90
Exhibit 11-6: PSO Plan Comparisons (Cont’d)....................................................................................................91
Exhibit 11-7: PSO Load Forecast Trends.............................................................................................................92
Exhibit 11-8: PSO Load Forecast Comparison ....................................................................................................93
Exhibit 11-9: PSO Reserve Margin......................................................................................................................94
Exhibit 11-10: PSO Hybrid Plan ..........................................................................................................................95
AEP-SPP 2009 Integrated Resource Plan
Exhibit 11-11: Comparison of SWEPCO Optimal and Suboptimal Plans ...........................................................98
Exhibit 11-12: SWEPCO Optimal Plan Comparison for Power and CO2 Price Scenarios ..................................99
Exhibit 11-13: SWEPCO Full Study Period Revenue Requirements.................................................................100
Exhibit 11-14: SWEPCO Full Study Period Cost over Optimal Plan ................................................................100
Exhibit 11-15: SWEPCO Plan Comparisons......................................................................................................101
Exhibit 11-15: SWEPCO Plan Comparisons (Cont’d) .......................................................................................102
Exhibit 11-16: SWEPCO Hybrid Plan ...............................................................................................................103
Exhibit 11-17: SWEPCO Load Forecast Comparisons ......................................................................................104
Exhibit 11-18 SWEPCO Reserve Margin With and Without Turk and Stall Plants ..........................................105
Exhibit 12-1A: Key Risk Factors–Weighted Means for 2009-2035 (PSO)........................................................107
Exhibit 12-1B: Key Risk Factors–Weighted Means for 2009-2035 (SWEPCO)...............................................108
Exhibit 12-2A: Cumulative Probability Distribution of AEP-SPP Revenue Requirement (PSO)......................109
Exhibit 12-2B: Cumulative Probability Distribution of AEP-SPP Revenue Requirement (SWEPCO).............109
Exhibit 12-3A: Probability Distribution of AEP-SPP Revenue Requirement (PSO) .........................................110
Exhibit 12-3B: Probability Distribution of AEP-SPP Revenue Requirement (SWEPCO).................................110
Exhibit 12-4: Basis of Capital Cost Distributions ..............................................................................................111
Exhibit 12-5A: Capital Cost Risk-Adjusted CPW 2009-2035 Revenue Requirement ($ Millions) (PSO) ....... 111
Exhibit 12-5B: Capital Cost Risk-Adjusted CPW 2009-2035 Revenue Requirement ($ Millions) (SWEPCO)111
Exhibit 12-6A: Distribution Function for All Portfolios (PSO) .........................................................................112
Exhibit 12-6B: Distribution Function for All Portfolios (SWEPCO).................................................................113
Exhibit 12-7A: Distribution Function for All Portfolios at > 95% Probability (PSO) .......................................113
Exhibit 12-7B: Distribution Function for All Portfolios at > 95% Probability (SWEPCO)...............................114
Exhibit 13-1: AEP-SPP Generation Capacity.....................................................................................................116
Exhibit 13-2: AEP-SPP Current Capacity Mix ..................................................................................................117
Exhibit 13-3: AEP-SPP 2019 Capacity Mix.......................................................................................................117
Exhibit 13-4: 2008 AEP-SPP 2030 Capacity Mix..............................................................................................118
Exhibit 13-5: Change in Energy Mix With Hybrid Plan - Current vs. 2019 and 2030.......................................119
Exhibit 13-6: 2009 AEP-SPP IRP ......................................................................................................................121
Exhibit 13-7: CO2 Emission Profile ...................................................................................................................122
Exhibit 13-8: CO2 Emission Profile With Caps..................................................................................................123
Exhibit 13-9: CO2 Emission Profile vs. Estimated Waxman-Markey Allocation ..............................................124
AEP-SPP 2009 Integrated Resource Plan
Appendices
Appendix A, Figure 1 Existing Generation Capacity, AEP-SPP Zone ..............................................................131
Appendix B, Figure 1 Economically Screened Renewable Alternatives ...........................................................132
Appendix C, Figure 1 Key Supply Side Resource Assumptions........................................................................133
Appendix C, Figure 2 Energy Storage Screening...............................................................................................134
Appendix D, Figure 1 AEP-SPP Capacity, Demand, Reserve Forecast.............................................................135
Appendix D, Figure 2 AEP-SPP Capacity, Demand, Reserve Forecast (High Demand Scenario)....................136
Appendix D, Figure 3 PSO Capacity, Demand, Reserve Forecast ....................................................................137
Appendix D, Figure 4 SWEPCO Capacity, Demand, Reserve Forecast ...........................................................138
Appendix E, Figure 1 AEP Plan to Meet 10% of Renewable Energy Target by 2020.......................................139
Appendix F, DSM By Operating Company .......................................................................................................140
Appendix G, Arkansas Stakeholder Report........................................................................................................141
AEP-SPP 2009 Integrated Resource Plan
Acknowledgements
The Resource Planning group appreciates the support and input of the various individuals
throughout the Service Corporation who provided input into the development of this Integrated
Resource Plan document. In addition, a number of people provided valuable comments as the report
was being developed including the operating company regulatory support staffs.
AEP-SPP 2009 Integrated Resource Plan
i
Executive Summary
The goal of resource planning is to match a utility’s future suite of resources with projected
demand for those resources. As such the plan lays out the amount, timing and type of resources that
achieve this goal at the lowest reasonable cost, considering all the various constraints – reserve
margins, emission limitations, renewable and energy efficiency requirements – that it is mandated to
meet. Planning for future resource requirements during volatile periods can be challenging.
Unprecedented economic contraction and varying levels of proposed regulation regarding greenhouse
gases and renewable energy are two major drivers of uncertainty that must be addressed during the
planning process. Over the 10-year, 2010-2019 Integrated Resource Plan (IRP or “Plan”) planning
period, the AEP’s integrated western zone (AEP-SPP) which includes Public Service Company of
Oklahoma (PSO) and Southwestern Electric Power Company (SWEPCO) is expected to experience
load growth at a compound annual rate of 1.5% per year, or roughly 140 MW annually. This growth
can be considered as occurring in two phases. The impact of the existing recession depresses peak
demand in 2009 and 2010 with a rapid increase in 2011 from the assumed economic recovery. In
addition, there is a comparable rate of growth for internal energy sales over the 10-year period, with
load factors increasing in 2011 due to the recovery of recession impacted industrial load.
The following Summary Exhibit 1 depicts the “going-in” capacity needs of PSO and SWEPCO
with committed capacity additions (Stall and Turk for SWEPCO, Exelon-Green Country PPA for
PSO) but excluding uncommitted planned capacity additions. It amplifies that the recent economic
downturn has reduced the need for new resources, beyond current commitments, to the end of the
planning horizon. However, PSO and SWEPCO must still make resource additions to satisfy reserve
requirements.
With the supply side additions and demand side measures that provide demand
reductions/energy efficiency (DR/EE or “DSM”) included in this 2009 IRP, Summary Exhibit 2
shows that PSO and SWEPCO will be able to meet their margin requirements without market
capacity purchases beginning in 2013.
AEP-SPP 2009 Integrated Resource Plan
ii
Summary Exhibit 1
PSO: Capacity Position
NO New Capacity Post-2012 L/T PPA…. NO 'New' Energy Efficiency/Demand Reduction (EE/DR)
2,500
3,000
3,500
4,000
4,500
5,000
5,500
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Year
MW- Summer Capacity
Installed Capacity (MW) Purchased Capacity (MW)
Est. Long-Term PPA Capacity (MW) Demand + SPP Margin (MW) (Nov 2008 Fcst)
Demand + SPP Margin (MW) (April 2009 Fcst)
SWEPCo: Capacity Position
NO New Capacity Post-Turk…. NO 'New' Energy Efficiency/Demand Reduction (EE/DR)
2,500
3,000
3,500
4,000
4,500
5,000
5,500
6,000
6,500
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Year
MW- Summer Capacity
Installed Capacity (MW) Purchased Capacity (MW)
Stall (2011) + Turk (2013) (MW) Demand + SPP Margin (MW) (Nov 2008 Fcst)
Demand + SPP Margin (MW) (April 2009 Fcst)
Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan
iii
Summary Exhibit 2
AEP SPP: (Summer Season)
Reflecting: Current Hybrid Plan
5,000
6,000
7,000
8,000
9,000
10,000
11,000
12,000
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Year
MW- Summer Capacity
Installed/Purchased Capacity (MW) New Capacity (MW)
Demand + SPP Margin (MW)(W/ DSM) Demand + SPP Margin (MW)(W/O New DSM)
Source: AEP Resource Planning
Both the proposed Turk (SWEPCO) baseload ultra-supercritical pulverized coal (USC-PC) plant
and a 509 MW Stall Natural Gas Combined Cycle were considered embedded for 2009 AEP-SPP
resource planning purposes, as they were secured during the SWEPCO 2006 Long-term Baseload
Resource Request For Proposal (RFP) process. These units are currently under construction with Stall
approximately 60% physically complete—with 95 % of the construction costs committed—and
scheduled to begin commercial operation prior to the summer peak of 2011 and Turk approximately
15% physically complete—with 81 % of the construction costs committed—and scheduled to be in
service prior to the summer peak of 2013. The 2008 PSO RFP process resulted in the selection of a
purchase power agreement (PPA) with Exelon for 512 MW of the Green Country combined cycle
facility which is also embedded in this IRP beginning 2012. Each project is fulfilling commission-approved
findings of need/necessity in Arkansas, Louisiana, Texas (Stall and Turk), and Oklahoma
(450 MW of baseload capacity), and are still required for meeting SPP minimum reserve margin
requirements.
AEP-SPP 2009 Integrated Resource Plan
iv
Major Drivers:
Global Climate Change
This 2009 IRP for AEP-SPP is consistent with the AEP 2009 Corporate Sustainability Report
with regard to the assumption of potential legislation related to greenhouse gas (GHG)/carbon dioxide
(CO2) emissions, renewable portfolio standards (RPS), and energy efficiency. The driving planning
assumptions include:
 CO2 mitigation in the form of substantive CO2 reduction legislation effective by 2015 with a
cap-and-trade regime effective in the same year.
 Prospect of a future Federal RPS, or a growing critical mass or “patchwork” of AEP state-legislated
RPS initiatives—which could be in the range of 10%, or more.
With that, AEP has positioned itself by assuming an aggressive posture in the adoption of
renewable alternatives including a 2,000 MW system-wide renewable initiative (by 2011).
That strategy would be an underpinning of an overall renewable energy target of 10% of
sales by 2020 and is consistent with the existing state renewable energy targets.
Demand Side Management and Energy Efficiency (DR/EE)
Recognizing the prospects of higher (avoided) costs, AEP initiatives to improve grid efficiency
and install advanced metering, and a national groundswell focused on efficiency, the AEP-SPP IRP
calls for:
 Approximately 78 MW of incremental DR/EE by 2010, growing to 389 by 2019.
 This is “incremental” since it is over-and-above current estimates of existing AEP-SPP
interruptible-type measures totaling over 48 MW at peak. However, it is inclusive of current
and pending energy efficiency programs at both PSO and SWEPCO.
Wind and Other Renewable Resources
Along with the prospects of CO2 legislation, the possible introduction of a Federal (or “en
masse” state) RPS, helped justify the planned system-wide purchase of 2,000 MW of renewable
resources—for planning purposes assumed to be in the form of wind power—by 1/31/2011. The
largest portion of these purchases is for AEP-East.1 When added to current and planned PSO and
SWEPCO long-term wind purchases as well as economically-screened wind and biomass co-firing
opportunities beyond the 10-year IRP period, these operating companies as well as AEP are
positioned to achieve 10% of energy sales from renewable sources.
Emerging Technology
AEP is committed to pursuing emerging technologies that fit into the capacity resource planning
process, including Sodium Sulfur (NaS) Batteries, fuel cells, solar panels, and “smart” grid enabling
meters. These “distributed” technologies, while currently expensive relative to traditional demand
1 Note: Firm “capacity” attributable to wind would be limited to roughly 8%, of the nameplate amount for
purposes of capacity planning in SPP.
AEP-SPP 2009 Integrated Resource Plan
v
and supply options, have the capacity to evolve into common resource options as costs come down
and the capabilities continue to improve. For each of these options, both the technology and
associated costs will continue to be monitored for increased inclusion in future planning cycles, if
warranted.
AEP-SPP Recommended Plan:
Complete the 509 MW Stall combined Cycle Facility in SWEPCO by the by the third quarter
of 2011 so it is ready for the summer peak in 2011
 Begin receipt of 512 MW of baseload/intermediate capacity from Green Country (Exelon
PPA) in PSO by summer of 2012
 Complete the joint owned (AEP share - 447 MW) Turk Ultra-Supercritical PC plant in
SWEPCO by the fourth quarter of 2012 so it is ready for the summer peak in 2013
 Purchase (or construction) of an additional 750 MW (nameplate) of wind generation by 2019
 Acquire 158 MW of peaking capacity in SWEPCO by 2019
Implement new DR/EE programs totaling 332 MW over the IRP planning period, or over 860
GWH annually after 2015.
The following Summary Exhibit 3 offers a view of the 2009 AEP-SPP IRP:
Summary Exhibit 3
RENEWABLE RENEWABLE
Environmental
Retrofits(G)
Embedded
Demand
Reduction(B)
(Cumul.
Contribution)
New
Demand
Reduction(C)
(Cumul.
Contribution)
Wind (Nameplate)
Environmental
Retrofits(G)
E mbedded
Demand
Reduction(B)
(Cumul. Contribution)
New
Demand
Reduction(C)
(Cumul.
Contribution)
Wind (Nameplate)
2009 9 0 10 0
2010 13 31 16 24 79.5(F)
2011 16 62 198 (E) 20 48 100
2012 19 94 24 72 100
2013 21 125 26 96 150
2014 22 157 FC1 (4) 29 120
2015 23 188 67 WSH2 (8) 30 144 33
2016 NE3&4 (15) 24 188 31 144 100
2017 25 188 200 32 144
2018 25 188 32 144
2019 25 188 32 144
Nameplate
Capacity
(15) 25 188 465 (12) 32 144 563
(SPP) Capacity
Value (Wind 8%; )
60 45
Cumul.
(Nameplate) 2% 16% 39% 2% 8% 30%
Cumul.
(Capacity)
Contribution 3% 24% 8% 2% 11% 42%
(G) Derate associated with the addition of and FGD system
Planned
Resource
Reductions
Planned
Resource
Reductions
PSO SWEPCO
THERMAL
Duty Cycle Type:
BL=Baseload
INT=Intermediate
PKG=Peaking
(Stall) 509-MW INT
2009 AEP-SPP Integrated Resource Plan (Hybrid Plan)
(B) "Embedded" DSM represents 'known & measurable', commission-approved program activity now projected by AEP-Economic Forecasting in the most recent
load forecast
157-MW PKG
1,113
Planned Resource Additions (MW) Planned Resource Additions (MW)
DSM
(E) Assumes Elk City and Blue Canyon V wind energy available by 2011, but firm transmission delayed until 2013
(C) "New" DSM represents incremental activity projected based on estimated contribution & program cost (vs. avoided cost) parameters, from recent Market Potential
Studies, and were generally limited to an EPRI Jan. '09 study identifying a "Realistically Achievable Potential". This 'New' (increm) DSM-DR activity modeled thru
2015 only
(D) PPA term for PSO 2012 baseload capacity & energy: 9 years, 7 months (thru 2021)
(Turk) 447-MW BL
DSM THERMAL
Duty Cycle Type:
BL=Baseload
INT=Intermediate
PKG=Peaking
(F) Assumes Majestic wind energy available by 2010, but firm transmission delayed until 2012
43%
(Grn Cntry PPA)
512-MW BL
60%
(A) Not shown are relatively small unit uprates and derates embedded in the current plan (e.g. FGD retrofit auxliary load losses)
512
65% 83%
Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan
vi
Plan Impact on Carbon Mitigation (“Prism” Analysis)
Global Climate Change and the prospect for comprehensive CO2 legislation has had a direct
bearing on the outcome of the 2009 AEP-SPP Plan. To gauge the respective CO2 mitigation impacts
incorporated into this resource planning, an assessment was performed that emulates an approach
undertaken by the Electric Power Research Institute (EPRI). This profiling seeks to measure the
contributions of various “portfolio” components that could, when taken together, effectively achieve
such carbon mitigation:
 Energy Efficiency
 Renewable Generation
 Fossil Plant Efficiency, including coal-unit retirements
 Nuclear Generation
 Technology Solutions, including Carbon Capture and Sequestration
The following Summary Exhibit 4 reflects those comparable components within this 2009 IRP–set
forth as uniquely-colored “prisms”—that are anticipated to contribute to the overall AEP System’s
(combined East and West regions) initiatives to reduce its carbon footprint:
Summary Exhibit 4
AEP-SYSTEM (East & West)
CO2 Emission Profile
Hybrid Plan (2009 IRP)
Including: 20 MW CCS by 20 1 0… 235 MW by 2013… 1,300 MW by 2020… 1,740 MW by 2025… 5,800 MW by 2030
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
CO2 Emissions, K Tonnes
(Pre-Committed) NSR Caps & Retirements
DR/EE
Renewables
Retirements (post-'R/R/R')
Cook Uprates
CCS Retrofits @ 90%
Hybrid Plan
2009 Hybrid Plan
(Assuming No Carbon Offsets or
Allowance Purchases)
"Business-As-Usual"
2005 (A)
144.9 M
62.5 M
Tonne
(35.8%)
Reduction
Source: AEP Resource Planning
While these results would suggest significant improvement in the AEP System CO2 emission
profile over time, it could still fall short of prospective legislation that would attempt to further limit
AEP-SPP 2009 Integrated Resource Plan
vii
CO2. Specifically, using H.R. 2454 (the Waxman-Markey Bill) that passed the U.S. House in June,
2009 as a proxy, this profile would require reduction in CO2 emissions that would have to consider
acquisition of carbon “offsets”—financial instruments that represent certified initiative to remove 1
ton of carbon—to begin to approximate the levels of reduction set forth by such mandates. The
following Summary Exhibit 5 offers such a comparison for the AEP System:
Summary Exhibit 5
AEP-SYSTEM (East & West)
CO2 Position vs. W-M Emission "Caps"
Hybrid Plan (2009 IRP)
Including: 20 MW CCS by 2010… 235 MW by 2013… 1,300 MW by 2020… 1,740 MW by 2025… 5,800 MW by 2030
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
CO2 Emissions, K Tonnes
(Pre-Committed) NSR Caps & Retirements
DR/EE
Renewables
Retirements (post-'R/R/R')
Cook Uprates
CCS Retrofits
Offsets (Domestic & Int'l)
Hybrid Plan with Offsets
W-M CO2 Target
62.5 M
Tonne
(35.8%)
Reduction
Waxman-Markey
(Physical Compliance) Targets
(3% by '12… 17% by '20… 42% by '30)
Assuming
20 M Tonne
of Carbon Offsets
Attainable by 2020
Source: AEP Resource Planning
Further, under the assumption that a cap-and-trade mechanism could emerge from any set of
carbon legislation, it is reasonable to assume that such CO2 mitigation efforts, inclusive of offset
acquisitions, may not provide for an adequate CO2 position within that mechanism. Specifically, if the
legislation provides for the allocation of an insufficient level of (free) CO2 allowances to the utility,
any such remaining CO2 position “shortfall” must subsequently be borne by the utilities’ customers
through additional, potentially more costly, CO2 mitigation efforts, including the purchase of
additional allowances. The following Summary Exhibit 6 identifies this potential position based on
the current allowance allocation format set forth by the Waxman-Markey Bill:
AEP-SPP 2009 Integrated Resource Plan
viii
Summary Exhibit 6
AEP-SYSTEM (East & West)
CO2 Position vs. Est. W-M LDC Allocations & Wholesale Recoveries
Hybrid Plan (2009 IRP)
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
CO2 Emissions, K Tonnes
(Pre-Committed) NSR Caps & Retirements
DR/EE
Renewables
Retirements (post-'R/R/R')
Cook Uprates
CCS Retrofits
Offsets (Domestic & Int'l)
Hybrid Plan with Offsets
W-M CO2 Target
Wholesale Allow. Recovery
W-M LDC Est. Allowance Alloc.
62.5 M
Tonne
(35.8%)
Reduction
~40 MM
Allowances
Required (2012)
~24 MM
Allowances
Required (2020)
or...
~4,800 MW "CCS-Equiv."
(@ ~5 MM T per 1GW CCS)
~69 MM
Allowances
Required (2030)
or...
~13,800 MW "CCS-Equiv."
(@ ~5 MM T per 1GW CCS)
Est. Utility (Retail) Allow. Allocation @
79 MM in 2012 under W-M "50/50"
distribution basis for Electricty Sector
allowance alloc
Waxman-Markey
(Physical Compliance)
Target
(17% by '20… 42% by '30)
Est. increm. allowance/cost
recovery from Wholesale
Customers
Source: AEP Resource Planning
In summary, this prism analysis would suggest that the carbon mitigation requirements in the
AEP System (East and SPP) 2009 IRPs offer a meaningful pathway to the attainment of potential
Climate Change/CO2 legislation, however, additional contributions–over-and-above the acquisition
of CO2 allowances—may be required in future planning cycles to protect AEP’s customers from
significant cost exposures.
Plan Impact on Capital Requirements
This Plan includes new capacity additions, as well as unit uprates and environmental retrofits.
Such generation additions require a significant investment of capital. Some of these projects are still
conceptual in nature, others do not have site specific information to perform detailed estimates;
however, it is important to provide an order of magnitude cost estimate for the projects included in
this plan. As some of the initiatives represented in this plan span both East and West AEP zones, this
Summary Exhibit 7 includes estimates for projects over the entire AEP system Generation (G)
functional discipline.
It is important to reiterate the capital spend level reflected on the Summary Exhibit 7 is
“incremental” in that it does not include “base”/business-as-usual capital expenditure requirements of
the “G” sector. Achieving this additional level of expenditure will therefore be a significant challenge
going-forward and would suggest the Plan itself will remain under constant evaluation and subject to
change.
AEP-SPP 2009 Integrated Resource Plan
ix
Summary Exhibit 7
Reflecting...
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 TOTAL Group %
By Type… (2010-2019)
IRP (New Generation) 362 306 321 110 175 281 306 302 177 634 2,974 25%
IRP (Response to Carbon / RPS Legislation) - - - 44 147 381 349 548 848 623 2,941 24%
362 306 321 154 322 662 655 850 1,025 1,257 5,915
Plus:
Environmental Compliance / Cook License Extension 58 242 519 794 1,039 1,297 866 839 439 33 6,126 51%
TOTAL INCREMENTAL "G" CAPEX 420 548 840 948 1,361 1,959 1,521 1,689 1,464 1,290 12,041
Annual % 3% 5% 7% 8% 11% 16% 13% 14% 12% 11%
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 TOTAL
By Operating Company… (2010-2019)
AEG 4 5 90 37 50 135 246 370 220 17 1 ,172
APCo 14 15 14 15 98 298 251 546 723 582 2 ,555
CSP 0 0 13 30 70 98 9 0 100 125 4 44
I&M 30 90 110 152 352 684 642 470 220 93 2 ,842
KPCo 2 18 100 150 190 154 102 90 5 0 8 11
OPCo 4 3 33 95 164 188 73 69 30 89 7 48
PSO 0 5 63 203 258 331 129 23 153 271 1 ,436
SWEPCO 366 412 417 267 179 72 70 122 15 114 2 ,033
TOTAL INCREMENTAL "G" CAPEX 420 548 840 948 1,361 1,959 1,521 1,689 1,464 1,290 12,041
Subtotal
AEP System (East & West)
PRELIMINARY (Incremental) "G" Capex Spend
2009 IRP (E&W)
Assuming 1,300 MW CCS (MT only ) by 2020… (w/ 1,740 MW by 2025 … 5,800 MW by 2030 )
2010-2019
($Millions)
Source: AEP Resource Planning
Conclusion:
The recommended plan provides the “lowest, reasonable cost” solution through a
combination of traditional supply, renewable and demand side investments. The tempered load
growth combined with additional renewable resources, increased DR/EE initiatives, completion of
Stall and Turk plants, and the execution of the Exelon PPA, will allow AEP-SPP to meet its resource
requirements through 2018 at which point new peaking capacity will be required. No new
uncommitted baseload capacity is required over the term of the forecast period.
Keep in mind that the planning process is a continuous activity; assumptions and plans are
continually reviewed as new information becomes available and are modified as appropriate. Indeed,
the resource expansion plan reported herein reflects, to a large extent, assumptions that are subject to
change. It is simply a snapshot of the future at this time. The Plan is not a commitment to a specific
course of action. The future, now more than ever before, is highly uncertain, particularly in light of
the current economic conditions, the movement towards increasing use of renewable generation and
end-use efficiency, as well as legislative proposals to control “greenhouse gases” which could result
in the retirement or retrofit of existing generating units, impacting the supply of capacity and energy
to AEP-SPP companies. The resource planning process is becoming increasingly complex given
pending legislative and regulatory restrictions, technology advancement, changing energy supply
fundamentals, uncertainty of demand and energy efficiency advancements all of which necessitate
flexibility in any ongoing plan. The ability to invest in capital-intensive infrastructure is increasingly
challenged in light of current economic conditions, and the impact on the AEP-SPP customers will
continue to be a primary planning consideration.
AEP-SPP 2009 Integrated Resource Plan
1
1.0 Introduction
This document contains the assumptions and steps required to develop the recommended
resource plan. Section 1 discusses the company and the resource planning process in general. Section
2 describes emerging industry issues and commodity forecasts that impact utilities including AEP.
Section 3 describes the implications of these issues as they relate to resource planning. Section 4
describes current supply resources, including transmission integration, and Section 5 discusses
projected growth in demand and energy which serves as the underpinning of the plan. Then Section 6
combines these two projected states (resources versus demand) to identify the need to be filled.
Sections 7 through 12 describe the analysis and assumptions that are used to develop the plan such as
planning objectives (Section 7), resource options (Section 8), evaluation of demand side measures
(Section 9), and fundamental modeling parameters (Section 10). The modeling process and portfolio
development, including the selection of the “Hybrid Plan” is covered in Section 11, and finally a risk
analysis of selected portfolios is performed in Section 12. Section 13 describes the findings and
recommendations and lastly, Section 14 describes the plan implementation.
1.1 IRP Process Overview
This report presents the results of the Integrated Resource Plan (IRP) analysis for the AEP-SPP
zone of the AEP System, covering the period 2009-2019, with additional planning modeling and
analyses conducted through the year 2030. The information presented with this IRP (“Plan”) includes
descriptions of assumptions, study parameters, methodologies, and results including the integration of
supply-side resources and demand-side management (DSM) programs. The IRP process is displayed
graphically in Exhibit 1-1.
The goal of the IRP process is to identify the amount, timing and type of resources required to
ensure a reliable supply of power and energy to customers at the least reasonable cost.
In addition to the need to set forth a long-term strategy for achieving regional reliability/reserve
margin requirements, capacity resource planning is critical to AEP due to its impact on:
 Determining Capital Expenditure Requirements—which represents one of the basic
elements of the Company’s long-term business plan.
 Rate Case Planning—many of AEP’s regulated operating companies will plan rate
recovery filings that will reflect input based on a prudent planning process.
 Integration with other Strategic Business Initiatives—generation/capacity resource
planning is naturally integrated with the Company’s current and anticipated environmental
compliance, transmission planning, and other corporate planning initiatives such as
gridSMARTsm.
1.2 Introduction to AEP
AEP, with more than five million American customers and serving parts of 11 states, is one of
the country’s largest investor-owned utilities. The service territory covers 197,500 square miles in
Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and
West Virginia.
AEP-SPP 2009 Integrated Resource Plan
2
AEP owns and/or operates 58 generating stations in the United States, with a capacity of
approximately 37,000 megawatts. AEP’s customers are served by one of the world’s largest
transmission and distribution systems. System-wide there are more than 39,000 circuit miles of
transmission lines and more than 213,000 miles of distribution lines.
AEP’s operating companies are managed in two geographic zones for resource planning
purposes. Its SPP zone, which comprises two companies in the Southwest Power Pool (SPP): Public
Service Company of Oklahoma (PSO) and Southwestern Electric Power Company (SWEPCO); and
its eastern zone, comprising Indiana & Michigan Power Company (I&M), Kentucky Power Company
(KPCo), Ohio Power Company (OPCo), Columbus Southern Power Company (CSP), Appalachian
Power Company (APCo), Kingsport Power Company (KgP), and Wheeling Power Company
(WPCo).2
Exhibit 1-1: IRP Process Overview
IRP Process
Integrated
Plan
for
Capacity
Resources
Integrated
Resource
Plan
for
Capacity
Resources
Q1 Q2
“Demand-Side”
Inputs
CP&B, Commercial
Operations
 Load & Demand
Forecast
 (Market) Purchase &
Sale of Firm Capacity &
Energy
 (Incremental) DR/EE
estimates
 Regional (PJM/SPP)
Reserve Requirements
“Supply-Side”
Inputs
Generation,
Commercial
Operations,Trans.
Planning
 Existing Unit Cap.,
Cost & Performance
Parameters
 New & Emerging
Generation Alternatives,
Cost & Perf. Parameters
 (Existing) Gen Oppor.
(Size, type, cost)
 (Emerging)
Transmission Issues &
Constraints
Unit Disposition Evaluation
Generation, Comm Ops, CP&B
 Development of Potential Unit
Retirement Profile
Tranche/Timing
Major Process Input/Parameters
‘MECO’
Modeling
Generation,
Strategic
Policy
Analysis
Least-cost
Environ.
Compliance
Analyses re
SO2, NOx, Hg
Strategist
Resource
Modeling
CP&B
 Least-Cost
Optimal Resource
Plan
 Sensitivity
Analyses (re price,
load, etc.)
 Create multiple
Generation
“Portfolio” Views
Utility Risk Simulation
Analysis (URSA)
Modeling
Market Risk Oversight
 Risk Simulation of Discrete,
Strategist-based LT Portfolios
across “Key Risk Drivers”
BASE
Plan
&
Scenarios
Financial /
Regulatory
Modeling
CP&B
 Financial /
Budgetary
Proformas
 Opco/Juris.
Cost-of-Service
and Revenue
Requirement
Impacts
Iterative Modeling
Iterate, as necessary, based on
emerging issues / planning criteria, risk
profiles, as well as corporate financial
and regulatory recovery constraints.
Plan Develop. & Validation
Emerging Planning Policies / Scenarios
Generation, SPA, Commercial Ops, Transmission Planning, CP&B, Regulatory, Legal
 Add’l Environmental Constraints (e.g. GHG/CO2)… Demand Response/Energy Efficiency / Renewable Portfolio
Standards / Carbon Offsets / Other Emerging Technology Alternatives
 AEP-Ohio, generation/planning ‘status’ post-ESP; other emerging opco/state-specific requirements
 RTO (PJM & SPP) business rule/protocol migrations & LT Transmission Planning (RTEP & STEP)
AEP
Strategic
Plan
Aurora
Funda-mental
Pricing
Modeling
CP&B,Strate-gic
Policy
Analysis,
Generation
Long-term
(regional)
Commodity
Pricing
Forecasts re
Energy,
Natural Gas,
Coals,
Emissions
Modeling within CP&B
Modeling outside of CP&B
Q4 Q3
Document / Filing
Corporate
(E & W) and
Operating
Co./State-specific
Plan
Documentation
and Filings
Louisiana
(rules pending)
Ohio
(rules pending)
Kentucky
Virginia
Indiana
Arkansas
Oklahoma
Source: AEP Resource Planning
2 Both KgP and WPCo are non-generating companies purchasing all power and energy under FERC-approved
wholesale contracts with affiliates APCo and OPCo, respectively. AEP also has two operating companies that
reside in the Electric Reliability Council of Texas (ERCOT), AEP Texas North Company (TNC) and Texas
Central Company (TCC). These companies are essentially “wires” companies only, as neither owns nor
operates generating assets within ERCOT.
AEP-SPP 2009 Integrated Resource Plan
3
Other than a discussion of the requirements of the FERC-approved AEP System Integration
Agreement (SIA), this document will only address 2009 resource planning for the AEP-SPP zone.
Planning for AEP affiliates residing in AEP-East has been communicated in separate documents.
1.2.1 AEP-SPP Zone:
The operating companies in AEP's SPP zone collectively serve a population of about 3.83
million customers (995,050 retail) in a 36,000 square mile area in parts of Arkansas, Louisiana,
Oklahoma, and Texas (see Exhibit 1-2). In 2008, the residential, commercial, and industrial
customers accounted for 29%, 27%, and 27%, respectively, of AEP-SPP's total internal energy
requirements of 42,868 GWh, including energy losses. The remaining 17% was supplied for use in
the other retail and wholesale categories.
AEP-SPP experienced an all-time peak internal demand of 9,120 MW on August 4, 2008. An
all-time winter peak internal demand, 6,902 was experienced on February 16, 2007.The capacity
resource planning of the respective AEP-SPP and East zones is performed on a mutually-exclusive
basis regardless of the covenants of the System Interchange Agreement (SIA).
Exhibit 1-2: AEP System, East and West Zones
Source: AEP Internal Communications
1.2.2 Embedded Baseload Assets
Both the proposed Turk (SWEPCO) baseload ultra-supercritical pulverized coal (USC-PC) plant
and a Stall Combined Cycle (CC) plant were considered embedded for 2009 AEP-SPP resource
planning purposes, as they were secured during the SWEPCO 2006 Long-term Baseload Resource
Request For Proposal (RFP) process. The 2008 PSO RFP process resulted in the selection of a
purchase power agreement (PPA) with Exelon for the 512 MW Green Country combined cycle
Focus of this
IRP
AEP-SPP 2009 Integrated Resource Plan
4
facility which is also embedded in this IRP. These additions were approved by the appropriate state
regulatory commissions based, in part, on the demonstrated need at the time the applications were
filed. During the past year, the economic downturn has lead to reduced load growth forecasts in the
near term. However, SWEPCO and PSO, respectively, still find these facilities necessary to the meet
the peak demand and energy needs of their customers. To illustrate this point, the Exhibit 1-2 for
PSO and Exhibit 1-3 for SWEPCO have been prepared to show the reserve margin exposure with
and without these resources.
Exhibit 1-3: PSO Reserve Margin With and Without Exelon PPA
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Reserve Margin
Under "Base" Demand Forecast:
Per 2009 Resource Plan 13.8% 13.2% 19.2% 19.7% 19.9% 20.3% 19.5% 19.3% 18.7% 18.1%
Exclusive of Exelon PPA (2012) 13.8% 13.2% 6.9% 7.4% 7.6% 7.9% 7.2% 7.1% 6.5% 6.1%
Under "Accelerated (High)" Demand Forecast:
Per 2009 Resource Plan 11.0% 8.2% 15.2% 14.8% 14.2% 14.2% 13.2% 12.6% 11.6% 10.9%
Exclusive of Exelon PPA (2012) 11.0% 8.2% 3.2% 3.0% 2.5% 2.5% 1.5% 1.1% 0.2% -0.5%
Reserve Margin -- MW Position
Above / 13.6% SPP Requirement)
Under "Base" Demand Forecast:
Per 2009 Resource Plan 6 (18) 232 253 259 275 242 237 211 190
Exclusive of Exelon PPA (2012) 6 (18) (280) (259) (251) (235) (268) (271) (297) (318)
Under "Accelerated (High)" Demand Forecast:
Per 2009 Resource Plan (108) (228) 65 51 26 24 (19) (46) (92) (124)
Exclusive of Exelon PPA (2012) (108) (228) (447) (461) (484) (486) (529) (554) (600) (632)
* Excludes short-term capacity transfers to/from affiliate Southwestern Electric Power Company
Note: Minimum Reserve Margin Requirement per SPP Criteria is 13.6%
PSO
Stand-Alone Reserve Margins*
Based on (April 2009) Demand Forecast "Banding"
10-Year 2009 IRP Period: 2010-2019
Source: AEP Resource Planning
Exhibit 1-4: SWEPCO Reserve Margin With and Without Turk and Stall Plants
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Reserve Margin
Under "Base" Demand Forecast:
Per 2009 Resource Plan 13.8% 14.0% 13.3% 22.0% 20.6% 22.3% 20.9% 19.4% 17.6% 19.2%
Exclusive of Turk (2013) 13.8% 14.0% 13.3% 13.1% 11.9% 12.8% 11.6% 10.1% 8.5% 7.1%
Exclusive of Stall (2011) & Turk (2013) 13.8% 3.7% 3.1% 3.1% 1.9% 2.0% 0.9% -0.4% -1.8% -3.1%
Under "Accelerated (High)" Demand Forecast:
Per 2009 Resource Plan 11.0% 10.6% 9.4% 16.9% 14.9% 15.6% 14.0% 12.0% 10.0% 11.2%
Exclusive of Turk (2013) 11.0% 10.6% 9.4% 8.5% 6.6% 6.6% 5.2% 3.4% 1.5% -0.1%
Exclusive of Stall (2011) & Turk (2013) 11.0% 0.6% -0.4% -1.2% -2.9% -3.6% -4.9% -6.5% -8.2% -9.6%
* Excludes short-term capacity transfers to/from affiliate Public Service Company of Oklahoma
Note: Minimum Reserve Margin Requirement per SPP Criteria is 13.6%
SWEPCO
Stand-Alone Reserve Margins*
Based on (April 2009) Demand Forecast "Banding"
10-Year 2009 IRP Period: 2010-2019
Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan
5
As these exhibits illustrate, reserve margin requirements would fall below the minimum SPP
criteria of 13.6% without these facilities under the most recent load forecast. AEP also prepared an
“Accelerated (High)” Demand Forecast which assumes a more robust recovery from the current
recession. Under this scenario, the need for the embedded assets is even more pronounced.
1.2.3 AEP System Interchange Agreement (East and West)
The 2000 System Interchange Agreement among AEPSC, as agent for the AEP-East, Central
and Southwest Inc. (CSW), and AEP-SPP operating companies, was designed to operate as an
umbrella agreement between the FERC-approved 1997 Restated and Amended CSW Operating
Agreement for its western (former CSW) operating companies and the FERC-approved 1951 AEP
Interconnection Agreement for its eastern operating companies. The System Interchange Agreement
provides for the integration and coordination of AEP’s eastern and western companies’ zones. In that
regard, the SIA provides for the option to transfer capacity and energy between the AEP-SPP zone
and under certain conditions the AEP-East zone. Since the inception of the SIA, AEP has continued
to reserve annually, the transmission rights associated with a prescribed (up to) 250 MW of capacity
from the AEP-East zone to the AEP-West zone. This transmission capacity has now been reserved
through 2013 and this reservation may be extended in five year increments.
1.2.4 AEP-SPP Operating Agreement –Company-Specific Obligations
The fundamental construct for this AEP-SPP IRP is that the initial planning evaluation be
performed on an integrated basis among the applicable operating companies–PSO and SWEPCO–so
as to leverage any opportunities such joint planning may offer as per the Operating Agreement.
Specifically, Section 9.2 of that 1997 Restated and Amended SPP (CSW) Operating Agreement
establishes that “…ownership share in each Joint Unit shall be allocated insofar as practical to
achieve a Prorated Reserve Level for all Companies participating in the Unit.”
However, the Operating Committee of the AEP-West Operating Agreement issued a formal
recommendation in December 2005, stating that the PSO and SWEPCO capacity-build as established
by the 2005 IRP cycle, and embedded within this 2009 IRP cycle, should not be considered for joint-ownership.
This is due to the significant amount of capacity required by both companies for each duty
cycle/type, and the parallel timing of those significant needs.
For the same reasons identified in 2005 by the Operating Committee, at a minimum, the
(embedded) build tranche through the nearer-term 2012 timeframe will naturally continue to be set
forth on a “stand-alone” (PSO and SWEPCO) basis. Therefore, largely for consistency and
considering the current, known intercompany firm transmission constraints between PSO and
SWEPCO that will be discussed in this 2009 report, as well as specific regulatory (needs
determination/cost recovery and competitive bidding) issues, subsequent new capacity resource
tranches (beyond 2012) will also be considered from a company-specific, stand-alone perspective.
That said, the ultimate makeup/ownership of such subsequent AEP-SPP capacity resource tranches
will likewise need to be reconsidered over future planning cycles from a shared-benefit perspective.
AEP-SPP 2009 Integrated Resource Plan
6
AEP-SPP 2009 Integrated Resource Plan
7
2.0 Current Resource Planning Issues in the Electric Utility Industry
2.1 Regulation/Deregulation
Both SWEPCO and PSO are regulated, and are expected to remain regulated throughout the IRP
ten-year period. This includes the portion of SWEPCO’s retail load residing in Texas, but outside of
ERCOT. Texas Senate Bill 547, which was signed into law in May 2009, statutorily delays retail
electric competition for SWEPCO in Texas until the proper infrastructure is in place. The new law
becomes effective September 1, 2009 and virtually assures that SWEPCO will remain regulated
during the period of the IRP.
2.2 Climate Change and Greenhouse Gases
A growing consensus of scientists concludes that the Earth’s climate is warming and that the
warming is due, at least in part, to anthropomorphic production of greenhouse gases (GHG). Many
gases exhibit greenhouse properties; some occur naturally, others are exclusively man-made. While
Carbon Dioxide (CO2) is the most prevalent and significant greenhouse gas in terms of its global
warming potential, there are other major greenhouse gases including methane (CH4), nitrous oxide
(N2O) and chlorofluorocarbons (CFCs).
Gases are typically quoted in terms of either CO2, carbon dioxide equivalents (CO2e) or carbon
equivalents (Ce). CO2 has an atomic weight of 44 while carbon has an atomic weight of 12. Thus,
CO2 equivalents are 3.67 times the mass of carbon equivalents, but the two measures have the same
relative purpose and can be used interchangeably if consistently applied. Anthropomorphic CO2 is
produced primarily from burning fossil fuels, a portion of which is used to produce electricity. In the
U.S., roughly one-third of GHG (measured in CO2e) result from the conversion of fossil fuels to
electricity.
Finally, the fuel and heat rate of the plant used in the production of electricity makes a
difference in the quantity of CO2 produced. Exhibit 2-1 demonstrates the advantage lower heat rates
(Btu/kWh) and fuel types can have.
Exhibit 2-1: Fossil Fuel-to-Electricity Emissions, by Fuel Type
0
0.2
0.4
0.6
0.8
1
1.2
6,000 6,500 7,000 7,500 8,000 8,500 9,000 9,500 10,000 10,500 11,000 11,500 12,000 12,500 13,000
Heat Rate
Tons CO2/MWh
Ultra Super Critical/ IGCC
Super Critical
Existing
Existing Steam
Combustion Turbine
Combined Cycle
Natural Gas
Coal
IGCC
Combined Cycle
Ultra-Supercritical
Supercritical Subcritical
Units with 90% Carbon Capture
Units without Carbon Capture
Natural Gas Coal
Source: AEP Resource Planning
AEP-SPP 2009 Integrated Resource Plan
8
2.2.1 Environmental Legislation
The electric utility industry, as a major producer of CO2, will be significantly affected by any
GHG legislation. During the 109th Congress (2005-2006), 106 bills, resolutions, and amendments
specifically addressing global climate change and greenhouse gas emissions were introduced. In
110th Congress, more than 235 bills were introduced that would put controls on the emissions of
greenhouse gases. One Senate bill, Lieberman-Warner, was voted out of the Senate Environmental
Committee and received floor consideration in June 2008. However, after a few days of debate, the
bill failed to pass a Senate cloture vote. The push towards federal climate change legislation is
continuing within the 111th Congress as well. The Waxman-Markey “American Climate and Energy
Security Act of 2009” was recently passed out of the House Energy and Commerce Committee, was
subsequently approved by the House of Representatives in June, and is now being considered by the
Senate. Virtually all of these bills employed “cap and trade” mechanisms (rather than carbon taxes)
with declining CO2 caps over time.
2.2.2 Impact of Environmental Legislation on Industry
Any binding legislation is likely to be “economy-wide”–generally meaning all fossil fuel use
will be targeted–because the production of GHG is not limited to specific sectors. Most legislation
that has been introduced to date is economy-wide. Furthermore, most legislation caps electric utility
emissions “downstream.” That is, electric generator emissions are limited, similar to the EPA’s
current programs that limit utility SO2 and NOx emissions.
2.2.2.1 AEP’s Assumption on CO2 Policy/Price
For the 2009 IRP cycle, the impact of CO2/GHG legislation on AEP’s long-term planning is
essentially modeled as a simple CO2 price beginning in 2015, as shown in Exhibit 2-2, that would
impact fossil unit dispatch cost.
Exhibit 2-2: CO2 Price Forecast
Emissions CO2 Index 2015 $/metric tonne = 1.0
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
5.0
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
CO2 2H08
Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan
9
2.2.2.2 Renewable Portfolio Standards
As identified in Exhibit 2-3, 29 states and the District of Columbia have set standards
specifying that electric utilities generate a certain amount of electricity from renewable sources. Most
of these requirements take the form of “renewable portfolio standards,” or RPS, which require a
certain percentage of a utility sales to ultimate customers come from renewable generation sources by
a given date. The standards range from modest to ambitious, and definitions of renewable energy
vary. Though climate change may not always be the primary motivation behind some of these
standards, the use of renewable energy does deliver significant GHG reductions. For instance, Texas
is expected to avoid 3.3 million tons of CO2 emissions annually with its RPS, which requires 2,000
MW of new renewable generation by 2009.
At the federal level, an RPS ranging from 10-20% was proposed for inclusion in the Energy
Independence and Security Act of 2007; but the final bill as passed into law did not contain an RPS.
However, a combined federal renewable energy standard (RES) and energy efficiency standard (EES)
of 20% was adopted as part of the Waxman-Markey bill passed by the House. The Senate also passed
out of Committee a combined 15% RES/EES and is also considering the House legislation.
Therefore, a federal RPS remains a distinct possibility in 2009 or 2010.
Exhibit 2-3: Renewable Standards by State
Renewable Portfolio Standards
State renewable portfolio standard
State renewable portfolio goal
www.dsireusa.org / July 2009
Solar water heating eligible *†
Extra credit for solar or customer-sited renewables
Includes separate tier of non-renewable alternative resources
WA: 15% by 2020*
OR: 25% by 2025 (large utilities)
5% - 10% by 2025 (smaller utilities)
CA: 20% by 2010
☼ NV: 25% by 2025*
☼ AZ: 15% by 2025
☼ NM: 20% by 2020 (IOUs)
10% by 2020 (co-ops)
HI: 20% by 2020
☼ Minimum solar or customer-sited requirement
TX: 5,880 MW by 2015
UT: 20% by 2025*
☼ CO: 20% by 2020 (IOUs)
10% by 2020 (co-ops & large munis)*
MT: 15% by 2015
ND: 10% by 2015
SD: 10% by 2015
IA: 105 MW
MN: 25% by 2025
(Xcel: 30% by 2020)
☼ MO: 15% by 2021
IL: 25% by 2025
WI: Varies by utility;
10% by 2015 goal
MI: 10% + 1,100 MW
by 2015*
☼ OH: 25% by 2025†
ME: 30% by 2000
New RE: 10% by 2017
☼ NH: 23.8% by 2025
☼ MA: 15% by 2020
+ 1% annual increase
(Class I Renewables)
RI: 16% by 2020
CT: 23% by 2020
☼ NY: 24% by 2013
☼ NJ: 22.5% by 2021
☼ PA: 18% by 2020†
☼ MD: 20% by 2022
☼ DE: 20% by 2019*
☼ DC: 20% by 2020
VA: 15% by 2025*
☼ NC: 12.5% by 2021 (IOUs)
10% by 2018 (co-ops & munis)
VT: (1) RE meets any increase
in retail sales by 2012;
(2) 20% RE & CHP by 2017
29 states & DC
have an RPS
5 states have goals
KS: 20% by 2020
AEP-SPP 2009 Integrated Resource Plan
10
2.2.3 AEP’s Voluntary Greenhouse Gas Mitigation Strategy
2.2.3.1 Plan through 2010
As a founding member of the Chicago Climate Exchange (CCX), AEP committed to
cumulatively reduce or offset 48 million metric tons of CO2 emissions from 2003 to 2010. Through
2008, AEP reduced or offset 51 million metric tons of CO2 — exceeding our target. We’ve done this
in a number of ways, such as improving power plant efficiency, replacing or retiring less efficient and
higher emitting units, increasing our use of renewable power, reducing SF6 emissions and investing in
forestry projects in the United States and abroad. For example, we have signed contracts to add 903
MW of wind capacity in the past two years — about 90 percent of our goal toward adding 1,000 MW
of wind by 2011. Consequently, we will double this goal and add a total of 2,000 MW of renewable
energy by the end of 2011, with regulatory support.
This will help AEP to further diversify its fuel portfolio. This plan contains a minimal 10
percent renewable energy target by 2020. AEP already plans to go beyond its initial commitment.
AEP has made significant progress in reducing a potent GHG — SF6 — which is found in some
electrical equipment. When AEP joined the Environmental Protection Agency’s (EPA) SF6 Emission
Reduction Partnership in 1999, our SF6 leakage rate was 10 percent. In 2008, this rate had been
reduced to 0.38 percent based on total system capacity, falling well below a self-imposed goal to
achieve a maximum 2.5 percent leak rate from 1996 levels. This was done by employing a
combination of technologies such as replacing SF6 insulated circuit breakers on lines to lower leakage
rates.
2.2.3.2 Post-2010 Plan For Voluntary Reductions
AEP’s post-2010 strategy is to voluntarily reduce or offset an additional 5 million tons of CO2
per year by purchasing offsets from projects such as forestry, reducing methane from agriculture,
adding more renewable energy in our portfolio and improving the efficiency of our power plants. The
investments AEP has made in its coal-fired power plants make them more efficient than the national
average for coal plants. Between 2001 and 2007, these improvements helped us to avoid burning 16.2
million tons of coal, preventing the release of 39 million tons of CO2.
AEP has signed contracts to add 903 MW of wind capacity in the past two years — about 90
percent of our original goal toward adding 1,000 MW of wind by 2011. In light of the increasing
number of state mandates and potential federal legislation, as well as the upcoming expiration of the
PTC, AEP will double this goal and add a total of 2,000 MW of renewable energy by the end of 2011,
with regulatory support. This will help us to further diversify our fuel portfolio. This integrated
resource plan contains a 10 percent renewable energy target by 2020.
As discussed in the following section, additional actions, including a future carbon capture and
storage program, will also help offset the anticipated growth in AEP’s carbon footprint.
2.2.3.3 The Role of Technology
Throughout its 100-year history, AEP has led the industry in advancing technology. The time is
right, with climate legislation on the horizon, to advance carbon capture technology to a commercial
scale. In March 2007 AEP signed agreements with world-renowned technology providers for carbon
AEP-SPP 2009 Integrated Resource Plan
11
capture and storage. A “product validation facility” is being constructed at the Mountaineer Plant in
West Virginia.
The Mountaineer project will employ Alstom’s chilled ammonia carbon capture technology
(Exhibit 2-4). Laboratory testing has shown that this process could capture more than 90 percent of
CO2 at a lower cost than other technologies that could be retrofitted at pulverized coal power plants.
A vendor-sponsored project demonstrating the technology was successfully completed on a 1.7 MW
(electric) slipstream at Pleasant Prairie a Wisconsin plant in 2008. This projected operated around the
clock for over 4,600 hours capturing 88 – 90 percent of CO2 emissions, and achieved purity levels
exceeding 99 percent.
Exhibit 2-4: CO2 Capture and Sequestration Process
Source: 2007AEP Corporate Responsibility Report
The chilled ammonia technology equipment is now being installed on AEP’s 1,300-MW
Mountaineer Plant as a 20MW (electric) product validation in the second half of 2009. It is designed
to capture approximately 100,000 metric tons of CO2 per year over a four to five year period, which
will be stored in deep geologic reservoirs. Battelle Memorial Institute is serving as AEP’s consultant
on geological storage. Following the completion of commercial verification AEP plans to scale up
the Mountaineer Chilled Ammonia Process (CAP) to capture CO2 from a 235 MWe slip stream.
AEP is seeking funding from the U.S. Department of Energy to then further scale up the Mountaineer
CAP to capture carbon dioxide from the entire flue gas stream. The expectation is for the commercial
scale technology to have a 90% capture rate of approximately 1.5 million tons of CO2 per year.
A second carbon capture technology AEP considered involves oxy-coal combustion. This
technology uses pure oxygen for the combustion of coal. Current generation technologies use air,
which contains nitrogen that is not used in the combustion process and is emitted with the flue gas.
By eliminating the nitrogen, this process leaves a flue gas that is a relatively pure stream of CO2 that
is ready for storage. At commercial scale, the CO2 likely would be stored in deep geologic
formations.
AEP-SPP 2009 Integrated Resource Plan
12
AEP’s vendor B&W completed a pilot demonstration and retrofit feasibility study in 2nd
Quarter 2008. Unfortunately, this technology proved to be cost prohibitive for use on our sub-critical
coal fleet.
2.3 Role and Impact of Commodity Pricing on Planning
Note: This section includes excerpts from the “Long Term Price Forecast 2009-2030: Return to
Fundamentals, 2H-2008” prepared by AEPSC’s Strategic & Economic Analysis Group (SEA) and
issued February 2009). Price forecasts are included in the Confidential Supplement.
The internal process utilized by AEP-SEA for projecting fundamental commodity pricing
utilized in long-term resource planning is
a time-intensive and iterative process.
Many factors ultimately affect power
prices as shown in Exhibit 2-5.
These numerous layers are also
interdependent. For instance, oil prices
affect rail transportation costs, which
impact coal prices, which impact SO2,
NOX, and power prices. It is easy to see
how minor deviations in one commodity
can have a trickle-down effect to power
prices.
The fundamental price drivers in the
modeling performed for the entire eastern
interconnect, as well as PJM, are the
assumptions around fuel prices, new
capacity builds and retirement, and load
growth. In the near term, fuel prices and
load growth play the most important role.
2.3.1 Power Prices
In the short-term, wholesale electricity prices remain extremely volatile due to the uncertainty in
the economy, environmental policy, and commodity markets. As such, the short term Reference price
does not fully capture the most recent market signals – see Confidential Supplement for a revised
short term forecast. In general, the Reference forecast overestimates current market prices.
In the mid-term, the value of the forecast resides less in the ability to precisely predict the power
price and more in the ability to accurately capture the trends in the power market. Starting in the mid-term,
the Reference Case begins to deviate from the external forecasts due to a range of views on
environmental policy and commodity markets. In particular, resolution on greenhouse gas (GHG)
legislation is expected to result in a range of power market trends.
In the Reference Case, carbon policy (2015) is incorporated in the power price – see Exhibit 2-
6. To an average coal market, the Reference carbon policy could represent an immediate increase in
Exhibit 2-5: Power Price Layers
Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan
13
the power price. In addition, the Reference carbon policy disproportionately impacts coal markets on
and off peak power prices. For example, in SPP on-peak prices increase 28% compared to 32% in the
off-peak market over the same period.
Exhibit 2-6: SPP On-Peak Price Index
SPP On-Peak Power Prices Index 2009 $/MWh = 1.0
0.0
0.5
1.0
1.5
2.0
2.5
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Source: AEP Fundamental Analysis
2.3.2 Fuel
2.3.2.1 Natural Gas
United States natural gas supply and consumption is currently rather loosely balanced because
of the global recession, but the market is still vulnerable to price spikes resulting from weather or
supply disruptions. Prices in 2009, while still reflective of Hurricane Ike-related supply loss, will
decline through 2012 as domestic natural gas production reverses its traditional decline due to
heretofore unconventional exploitation plays (see Exhibit 2-7).
Beyond 2014, unconventional natural gas production, buoyed by technology advancements,
provide adequate supply to meet demand when given long-term price signals above finding and
production costs of approximately $5.00 - $6.00/MMBtu (in 2008 dollars). The factor that will most
likely shape the fundamentals of overall gas demand will be the growth of gas consumption for
electricity generation. Additionally, the Alaskan Pipeline, projected to be on line in 2023, will deliver
gas from the North Slope to the Chicago Citygate.
Exhibit 2-7: Natural Gas Price Index
Gas Price PEPL TX-OK Index (2H08 2009 $/mmBtu = 1.0)
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
PEPL TX-OK 2H08
Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan
14
2.3.2.2 Coal
Coal is a unique commodity that comes with many different specifications. Coal is traded over-the-
counter at relatively thin volumes. The majority of coal transactions are done through contracts
between sellers and buyers, which sometimes results in significant differences between coal spot
prices and contract prices. Because of the high percentage of transportation cost relative to total
delivered coal cost and the significant capital investment required for a boiler to switch from one type
of coal to another, Btu and/or SO2 spreads may not hold when comparing different types of coal. In
addition to coal quality, reliability of coal delivery is another factor to consider in coal pricing. The
forecast (Exhibit 2-8) represents coal prices under a contract of 2-5 years, rather than spot prices.
During 2008, both international and U.S. domestic coal markets were on a rollercoaster. In
January of 2008, the international coal supply chain was disrupted by coal mine region flooding in
Australia, severe winter storm in China, and power outages in South Africa. As a result of these
events, coal producers in Australia declared force majeure for their mines in the flooding region, the
Chinese government issued an order to suspend its coal exports, and South Africa reduced its coal
output and exports.
International coal markets reacted to the coal supply disruptions and pushed coal prices even
higher for both thermal and metallurgical coals. High coal prices in international markets created a
great opportunity for U.S. coal producers to gain higher profits by exporting coal to international
markets rather than selling it in domestic markets. The increase in U.S. coal exports drained U.S.
domestic coal supply, especially in the Appalachian region, because of its location advantage for coal
export and its high energy content.
Exhibit 2-8: PRB Coal Price Index
COAL PRB FOB Index 2H08 2009 $/ton = 1.0
0.0
0.5
1.0
1.5
2.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
PRB 8800 2H08
Source: AEP Fundamental Analysis
Now, the situation of supply shortage of metallurgical coal has reversed due to the global
economic downturn. Demand for steel has been reduced dramatically, and the international
metallurgical coal benchmark at Newcastle of Australia is expected to be around $130/metric ton.
This is much lower than the $300/metric ton peak in 2008. The U.S. metallurgical coal exports fell
and the metallurgical coal producers in Appalachia are cutting their production, in contrast to
production expansion in early and middle 2008. For example, Consol closed its Mine 84, citing low
metallurgical coal prices.
AEP-SPP 2009 Integrated Resource Plan
15
2.3.3 New Build Cost
The capital cost forecast trends for pulverized coal, integrated gasification combined cycle
(IGCC), and nuclear power plants show similar trends. Capital costs have increased significantly from
rising materials, equipment, and labor. However, costs have declined recently due to the credit crisis
and economic concerns. Demand has dropped as companies look to delay their project schedules or
cancel projects outright. Demand has also dropped from industries that share similar materials and
labor with the energy industry. These factors lead to a downward trend in forecasts in the near term.
Longer term shows a slight upward trend, as demand returns in future years.
Given the trend for natural gas units to be built due to the combination of low capital cost, short
time frame to build, environmental uncertainty, and relatively lower gas price projections, the cost of
a gas plant will be driven more on the physical supply chain constraints of constructing the plant
versus the variable cost of the plants as seen in the base load unit profile. Gas plants are unlikely to
follow the downward projection of steel prices.
Renewable capacity offers almost no variable cost and for some renewables, reasonable capital
cost. However, the reliability and the amount of land required for renewable is a concern. The
primary driver for renewable build will be the environmental policies and technical improvements to
lower the cost of renewable generation and the build out of transmission capacity to move the wind
energy to the load centers.
Wind power has also experienced recent high material and equipment costs, as well as a
sharp increase in demand. U.S. wind power projects have increased significantly in recent years.
Reduced material costs and slower future growth rates may lead to wind power cost forecasts trending
downward in the near term.
Solar power is still in its early stage for wide commercial applications for power generation.
It is not as prevalent commercially as other types. Near term solar forecasts will benefit from reduced
material costs. Longer term forecasts show additional benefits as the technology develops and solar
power enjoys a better economy of scale.
2.3.4 Load Growth
The most overriding short-term concern for the economy is the recession. The National Bureau
of Economic Research (NBER), the official arbiter of the timing of recessions, has stated that the
recession began in December 2007. NBER utilizes data beyond the classic real Gross Domestic
Product (GDP) to gauge the beginning and ending of recessions. As an aside, the common definition
of recession is two consecutive quarters of negative GDP growth. The current recession has been
lengthy when compared with previous post World War II recessions. The longest recessions in this
period were 16 months and it appears likely that this economic downturn will exceed this length.
2.3.5 Emissions
2.3.5.1 SO2, NOX, and Mercury (Hg)
Environmental policy is one of the most fluid and unstable factors impacting the accuracy of the
long-term forecast. Policy options range from the Business-As-Usual Case (government policy is
AEP-SPP 2009 Integrated Resource Plan
16
very unlikely to become less regulated) to an extremely restrictive option with the potential to
significantly alter how the country fuels its electricity consumption.
On February 8, 2008, the D.C. Court vacated the Clean Air Mercury Rule (CAMR) governing
the release of mercury emissions. Today, there are no uniform technology standards or market-based
programs for mercury in the states in which AEP operates, although some other states have
established mercury control programs. According to the Environmental Group, Federal action is
anticipated and could become effective in 2014 when a command-and-control policy could require all
coal units to install either a mercury-specific control technology such as Activated Carbon Injection
(ACI) or Flue Gas Desulphurization/Selective Catalytic Reduction (FGD/SCR) emissions control
equipment. For development of market scenarios, the 2H08 forecast limits the FGD/SCR
installations to projects currently under construction as a result of equipment economics and the
evolution in emission regulations.
There is also a strong possibility that a plant-by-plant standard will replace a mercury trading
system. If this is the case, a dispatch price would not be required, but additional controls such as
baghouses or ACI would be needed. This could have an impact on proposed retirement dates of older,
non-controlled units and ultimately the timing for new capacity. When new standards and
implementation timelines are known, our plan will be re-evaluated and adjusted accordingly.
On July 11, 2008, the D.C. Circuit Court invalidated the Clean Air Interstate Rule (CAIR), and
the rule has been remanded to EPA. Today, policy alternatives remain fluid. The AEP Environmental
Group expects the CAIR program to be replaced with a more restrictive policy. In particular, the
absence of any guidance from EPA, the Environmental Group has postulated a scenario in which SO2
and NOx emissions will be 10 percent below the CAIR Phase II limits (fully implemented by 2025)
and exclude an allowance bank to meet emission targets. In the 2H08 forecast, annual NOx emissions
require a $1,000/ton price signal to remain in compliance, while SO2 emissions require a significant
price signal and an allowance bank to meet emission targets (Exhibit 2-9). The consultant forecast
represents the uncertainty associated with a replacement to CAIR, where policy options range from a
command-and-control policy (CERA-Breakpoint) to an additional constraint applied to the current
policy. However, the cap-and-trade policies typically include an allowance bank to meet emission
targets.
AEP-SPP 2009 Integrated Resource Plan
17
Exhibit 2-9: SO2 Emission Price Index
Emissions SO2 Index 2H08 2009 $/ton = 1.0
0
5
10
15
20
25
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
SO2 2H08
Source: AEP Fundamental Analysis
2.3.5.2 CO2
The forecasting of future CO2 allowance prices is subject to considerable uncertainty as the
underlying assumptions are entirely predicated upon a yet to be defined federal climate policy.
Strategic Policy Analysis has developed three potential CO2 price forecasts for each of the cases
(Exhibit 2-10). These forecasts attempt to represent a range of potential policy outcomes and
resulting pricing to account for the uncertainty. The Abundance and Constrained Cases are based on
the realistic limits of U.S. climate policy given current political and economic realities, while the
Reference Case is a weighting of the high and low forecasts and represents the most likely price
trajectory. Note: As the political and economic situation changes so will the politically acceptable
pricing range and likely pricing trajectory.
Exhibit 2-10: CO2 Emission Price Index
CO Price Index, Reference Case 2015 $/metric tonne = 1.0
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
Low CO2 Reference High CO2
Source: AEP Fundamental Analysis
The price forecasts were developed at the beginning of 2009 based on public analyses of two of
the most prominent pieces of comprehensive U.S. climate legislation; the “Low Carbon Economy Act
of 2007” introduced by Senators Bingaman and Specter and the “Climate Security Act of 2008”
AEP-SPP 2009 Integrated Resource Plan
18
introduced by Senators Lieberman and Warner. The Bingaman-Specter bill was widely supported by
industry for its moderate emission reduction timeline, while the Lieberman-Warner was praised by
environmentalists for its more aggressive emission reduction timeline. Thus, these bills represent
relative “bookends” for likely climate policy outcomes.
*******************End of 2H08 Fundamental Analysis excerpt***********************
2.4 Issues Summary
The increasing number of variables and their uncertainty has added to the complexity of
producing an integrated resource plan. No longer are the variables merely the cost to build the
generation, a forecast of what had traditionally been stable fuel prices and growth in demand over
time. Highly volatile fuel prices, and uncertainty surrounding the economy and environmental
legislation require that the process used to determine a resource plan is sufficiently flexible to
incorporate more subjective criteria. The introduction of a cap-and-trade system and high capital
construction costs weigh unfavorably on solid-fuel options, but conclusions must be metered with the
knowledge that there is a great deal of uncertainty.
One way of dealing with uncertainty is to hedge one’s bets. That is, if there exists the potential
for very expensive carbon legislation, one might favor a solution that minimizes carbon emissions,
even if that solution is not the least expensive. While there may not yet be a national RPS, procuring
or adding wind generation resources now will put a company ahead of the game if one does come to
pass. In this way, the company is trading future uncertainty for a known cost. Lastly, adding
diversity to the generating portfolio reduces the risk of the overall portfolio. That may not be the least
expensive option in a “base” (or most probable) case, but it minimizes exposure to adverse future
events and could reduce the ultimate cost of compliance if the resultant demand for renewable
resources continues to grow, outpacing the supplier resource base akin to past experience associated
with the “dash to gas”..
The long-term planning horizon is characterized by several primary variables. First and
foremost, the prospect of legislation that in some way regulates GHGs. Any system enacted will likely
result in:
 Ultimate development and implementation of CO2 capture and sequestration technologies
which, in the east where higher-quality bituminous coals are prevalent, could ultimately
favor current Integrated Gasification Combined Cycle (IGCC) design technology over
traditional Pulverized Coal (PC) plants.
 Implementation of Renewable Portfolio Standards, either at a state or, ultimately, a national
level.
 Efficiency improvements, both supply and demand side.
 A system for offsetting CO2 emissions.
 Potential for volatile natural gas pricing marked by the offsetting effects of both increased
supply and increased demand.
AEP-SPP 2009 Integrated Resource Plan
19
 Emissions allowance prices in light of the as yet unresolved CAIR and CAMR/mercury
requirements, assumptions directly affecting the economic viability of uncontrolled coal
generation.
Finally, the IRP process was complicated further by the economic slowdown that escalated in
late 2008, which resulted in very different near-term commodities forecasts. The 2H08 forecast was
completed prior to this economic slow down. However, after comparing the long-term commodities
forecasts used in this IRP (the 2H08 Forecast) to the subsequent long term forecast prepared in the
Spring of 2009 (1H09 Forecast) as shown in Exhibit 2-11 it was apparent that the effects of the revised pricing
estimates were negligible after 2013 and did not warrant a new resource evaluation.
AEP-SPP 2009 Integrated Resource Plan
20
Exhibit 2-11: 2H08 vs. 1H09 Commodities Comparison
SPP On-Peak Power Prices Index (2H08 2009 $/MWh = 1.0)
0.0
0.5
1.0
1.5
2.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
On-Peak 1H09 On-Peak 2H08
COAL PRB FOB Index (2H08 2009 $/ton = 1.0)
0.0
0.5
1.0
1.5
2.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
PRB 8800 1H09 PRB 8800 2H08
Gas Price PEPL TX-OK Index (2H08 2009 $/mmBtu = 1.0)
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
PEPL TX-OK 1H09 PEPL TX-OK 2H08
Source: AEP Fundamental Analysis
AEP-SPP 2009 Integrated Resource Plan
21
3.0 Implications of Industry Issues in this IRP Cycle
3.1 Demand Response/Energy Efficiency (DR/EE)
The AEP System (East and West/SPP zones) has adopted peak demand reduction and energy
efficiency goals which are 1,000 MW and 2,250 GWh, respectively by year-end 2012. Concurrently,
several states served by the AEP System have mandated levels of efficiency and demand reduction.
There also exists the possibility of federally mandated efficiency levels. While this IRP establishes a
method for obtaining an estimate of DR/EE that is reasonable to expect for the zone, as a whole; the
ratemaking process in the individual states will ultimately shape the amount and timing of DR/EE
investment. As those processes evolve and mature, the “order of magnitude” estimates can be refined
and replaced with definitive programs.
3.2 Renewables
Renewable Portfolio Standards and goals have been enacted in over one half of the states in the
U.S. Adoption of further RPS at the state level or the enactment of Federal carbon limitations or
RPS, will impose the need for adding more renewables and the potential expenditure of billions of
dollars.
Wind is currently one of the most viable large-scale renewable technologies (with incentives)
and has been added to utility portfolios mainly via long-term power purchase agreements. Recently,
many IOUs have begun to add renewable assets to their portfolios. The best sites in terms of wind
resource and transmission are rapidly being secured by developers. Further, while an extension of the
Federal Production Tax Credit (PTC) for wind projects - to the end of 2012 - was enacted in February
2009, it will probably not be extended further as the implementation of Federal carbon or RPS is
expected to make unnecessary the incentive provided by the PTC. Acquiring this renewable energy
and/or the associated Renewable Energy Credit (REC) or Carbon Offset now will likely limit the risk
of increased cost that comes with waiting for further legislative clarity in the AEP states.
In early 2007, AEP committed to the acquisition of energy from 1,000 MW (nameplate) of
additional wind generation projects by the end of 2010 via long-term purchase power agreements as
part of AEP’s comprehensive strategy to address greenhouse gas emissions. In light of progress in
meeting this commitment, the goal was expanded in early 2009 to 2,000 MW by the end of 2011.
SWEPCO is already receiving energy from one wind project with nameplate rating of 79.5 MW.
Additional contracts have been executed for PSO for an additional 198 MW to be placed in service by
December, 2009 which will result in a total of 591 MW or approximately 12 percent of PSO’s energy
needs being met with renewables. Exhibit 3-1 lays out the AEP-SPP zone’s renewable plan by
operating company to meet its share of this target.
As can be seen in Exhibit 3-1, PSO and SWEPCO have a greater contribution to the renewable
goal than the remaining AEP companies. This is due to wind being economically favored in states
like Oklahoma and Texas, particularly due to the higher wind profile. Wind is the primary source of
renewable energy in the AEP plan.
AEP-SPP 2009 Integrated Resource Plan
22
Exhibit 3-1: Renewable Energy Plan Through 2030
AEP SYSTEM
Solar Wind
Biomass
Rnwbl Solar Wind
Biomass
Rnwbl Solar Wind
Biomass
Rnwbl Solar Wind
Biomass
Rnwbl
Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent Nmplt Nmplt Equiv Percent
(MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales (MW) (MW) (MW) of Sales
2009 0 393 0 9.4% 0 31 0 0.6% 0 424 0 5.0% - 4 99 - 1.3%
2010 0 393 0 9.0% 0 111 0 2.3% 0 503 0 5.6% 10 1 ,029 - 2.5%
2011 0 591 0 13.3% 0 211 0 4.3% 0 801 0 8.6% 13 2 ,027 1 0 4.5%
2012 0 591 0 12.8% 0 311 0 6.3% 0 901 0 9.5% 15 2 ,827 1 09 6.4%
2013 (b) 0 591 0 12.7% 0 461 0 9.3% 0 1,051 0 10.9% 29 3 ,477 2 35 8.0%
2014 0 591 0 12.6% 0 461 0 9.2% 0 1,051 0 10.9% 42 3 ,477 2 35 8.0%
2015 0 658 0 14.0% 0 494 0 9.8% 0 1,151 0 11.8% 56 3 ,577 3 85 8.8%
2016 0 658 0 13.9% 0 594 0 11.6% 0 1,251 0 12.7% 70 3 ,777 3 85 9.1%
2017 0 858 0 18.0% 0 594 9 11.7% 0 1,451 9 14.7% 83 3 ,977 3 94 9.6%
2018 0 858 0 17.9% 0 594 9 11.6% 0 1,451 9 14.6% 100 3 ,977 5 21 10.1%
2019 0 858 0 17.8% 0 594 9 11.4% 0 1,451 9 14.5% 118 3 ,977 6 50 10.5%
2020 0 1,058 0 21.8% 0 594 9 11.3% 0 1,651 9 16.3% 133 4 ,377 6 50 11.3%
2021 0 1,058 0 21.6% 0 694 9 12.9% 0 1,751 9 17.0% 168 4 ,627 7 77 12.2%
2022 0 1,058 0 21.4% 0 794 9 14.6% 0 1,851 9 17.9% 220 4 ,827 7 77 12.6%
2023 0 1,158 0 23.3% 0 794 9 14.4% 0 1,951 9 18.6% 220 5 ,027 9 04 13.3%
2024 0 1,158 0 23.1% 0 894 9 16.0% 0 2,051 9 19.4% 271 5 ,327 9 04 13.9%
2025 0 1,158 0 22.9% 0 994 9 17.4% 0 2,151 9 20.0% 271 5 ,527 9 04 14.1%
2026 17 1,258 0 24.8% 17 994 9 17.3% 35 2,251 9 20.8% 340 5 ,727 9 04 14.5%
2027 17 1,258 0 24.6% 17 1,094 9 18.8% 35 2,351 9 21.5% 340 5 ,927 1 ,032 15.2%
2028 35 1,258 0 24.5% 35 1,094 9 18.7% 69 2,351 9 21.4% 409 6 ,127 1 ,032 15.5%
2029 35 1,358 0 26.2% 35 1,194 9 20.0% 69 2,551 9 22.8% 409 6 ,327 1 ,032 15.7%
2030 56 1,358 0 26.0% 56 1,394 9 23.1% 112 2,751 9 24.4% 496 6,527 1,032 16.1%
(a) Data EXCLUDES:
o AEP-Texas Central Co. & AEP-Texas Northern Co... as current and potential future state/federal RPS would be applicable to LSEs only.
o Conventional (run-of-river) hydro energy as a renewable source as it has been excluded from certain state and proposed federal RPS criteria…
Should hydro be ultimately included, it would contribute roughly 1% to the AEP System target by 2020.
(b) 2012/2013 represent the initial years for Federal RPS/RES mandates as currently proposed by several draft bills before Congress. Further, 2013
would represent the initial year after the likely expiration of Production Tax Credits (PTC) for, particularly, wind resources. The notion being that
establishment of a Federal renewables standard would likely eliminate further extension of such PTC opportunities.
PSO SWEPCO AEP-SPP
AEP Sytem - SPP Zone
Potential Renewables Profile to Achieve a 7% System Target by 2013, 10% by 2020, and 15% by 2030 (a)
...as well as Known or Emerging State-Specific Mandates
2009 IRP
Source: AEP Resource Planning
3.3 Carbon Capture & Storage/Sequestration (CCS)
Utility applications of CCS technologies continue to be developed and tested, and as such are
not yet commercially available on a large scale. However, given the focus on the advancement and
associated cost reduction of such technologies, it is likely to become both available and cost-effective
at some point over the IRP’s longer-term planning horizon (through 2030). However, this is very
dependent on the type of federal climate legislation that is passed and the degree to which there is
financial support for CCS technology in such legislation. Assuming carbon capture and storage
becomes commercially viable weight must be given to the options that are most readily adaptable to
this technology
3.4 Emission Compliance
Emission compliance requirements have a major influence on the consideration of supply-side
resources for inclusion in the IRP because of their potential significant effects on both capital and
operational costs. The AEP System’s strategy for complying with Title IV of the Clean Air Act
Amendments of 1990, as well as recent regulations tied to environmental air emissions, takes into
consideration additional power plant emission reduction requirements for SO2, NOx, and mercury
(Hg) emissions.
Specifically, in 2005, the U.S. Environmental Protection Agency (USEPA) established new
emission regulations for these pollutants as part of the CAIR (which the D.C. Circuit Court
AEP-SPP 2009 Integrated Resource Plan
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overturned on July 11, 2008), the now vacated Clean Air Mercury Rule (CAMR), and Clean Air
Visibility Rule (CAVR) rulemaking. Further, on-going debate over CO2/GHG emissions, particulate
matter (PM), and regional haze, as well as the previously mentioned potential enactment of additional
state and/or Federal RPS will likewise influence future capacity resource planning surrounding
decisions to retrofit, modify operations, or retire/mothball generating assets.
Certain PSO and SWEPCO coal and gas-fired generating units are subject to CAVR and
application of Best Available Retrofit Technology (BART) for SO2 and NOX. PSO will be equipping
its units with NOX combustion technology to meet BART limits for NOX and is expected to install
flue gas desulfurization technology (FGD) at the Northeastern 3 & 4 coal units to meet BART limits
for SO2 and PM. The specific timing of these installations is uncertain as the Oklahoma Department
of Environmental Quality is still developing its State Implementation Plan for the CAVR program.
SWEPCO plans to install FGD at Flint Creek station to meet CAVR.
AEP-SPP 2009 Integrated Resource Plan
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AEP-SPP 2009 Integrated Resource Plan
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4.0 Current Resources
The initial step in the IRP process is the demonstration of the region-specific capacity resource
requirements. This “needs” assessment must consider projections of:
 Existing capacity resources—current levels and anticipated changes
 Anticipated changes in capability due to efficiency and/or environmental retrofit projects
 Changes resulting from decisions surrounding unit disposition evaluations
 Regional and sub-regional capacity and transmission constraints/limitations
 Load and (peak) demand (see Section 5.2.)
 Current DR/EE (see Section 5.3.)
 SPP capacity reserve margin and reliability criteria (see Section 6.1.)
In addition to the establishment of the absolute annual capacity position, an additional “need” to
be discussed in this section will be a determination of the specific operational expectation (duty type)
of generating capacity–baseload vs. intermediate vs. peaking.
4.1 Existing PSO and SWEPCO Generating Resources
Appendix A offers a summary of all owned supply resources for the AEP-SPP zone plus long-term
wind contracts. The current (June 1, 2009) AEP-SPP summer supply of 9,216 MW is composed
of the following (with wind projects’ capacity at ratings allowed by SPP, generally about 8% of
nameplate):
Exhibit 4-1: Existing PSO and SWEPCO Generating Resources
PSO SWEPCO Total
Coal/Lignite 1,026 MW 2,680 MW 3,706 MW
Gas/Diesel 3,384 MW 2,086 MW 5,470 MW
Wind 17 MW -- 17 MW
Total 4,427 MW 4,766 MW 9,193 MW
Source: AEP Resource Planning
4.2 Capacity Impacts of Environmental Compliance Plan
As detailed in Exhibit 4-2 and Appendix D, the capability forecast of the existing generating
fleet reflects 27 MW in unit de-ratings associated with environmental retrofits - largely flue gas
desulphurization (FGD), and activated carbon injection with a baghouse (ACIBH) or with an
electrostatic precipitator (ACIESP) over the IRP period.
AEP-SPP 2009 Integrated Resource Plan
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Exhibit 4-2: PSO and SWEPCO Capacity Change After June 2009
Unit and Cause Year (a) Capacity Impact Year (a) Capacity Impact
Welsh 2 (FGD) 2013 -8 2015 -8
Flint Creek 1 (FGD) 2014 -4 2014 -4
Pirkey 1 (ACIESP) 2014 0 -- --
Dolet Hills 1 (ACIESP) 2014 0 -- --
Flint Creek 1 (ACIESP) 2014 0 -- --
Welsh 1 (ACIBH) 2014 -11 -- --
Welsh 2 (ACIESP) 2014 0 -- --
Welsh 3 (ACIBH) 2014 -11 -- --
Northeastern 3 (FGD + ACIESP) 2014 -7 2016 -7
Northeastern 4 (FGD + ACIESP) 2014 -8 2016 -8
Oklaunion 1 (ACIESP) 2014 0 -- --
Net Change -49 -27
Note : (a) Summer season of effective SPP delivery year.
As Modeled In Final Plan
AEP West Capacity Changes (MW) after June 1, 2009
Source: AEP Resource Planning
4.3 Existing Unit Disposition
A long-term view of disposition alternatives facing older units in the AEP-SPP region was
established. The work group affirmed the findings of previous studies, recommending no unit
disposition planned for the IRP period. In general, the capacity value provided by the older units far
outweigh the fixed costs associated with their continued operations, The work group report is include
in the technical addendum.
4.4 AEP-SPP Transmission
4.4.1 Transmission System Overview
The western Transmission System, which consists of the transmission facilities of the four
western AEP operating companies, is operated in both the SPP and ERCOT. The western
Transmission System spans portions of four states and comprises nearly 10,000 miles of circuitry
operating at or above 69 kV.
The portion of the western Transmission System operating in SPP (AEP-SPP zone) consists of
approximately 1,270 miles of 345 kV, approximately 3,400 miles of 138 kV, and 2,197 miles of 69
kV. The AEP-SPP zone is also integrated with and directly connected to ten other companies at 87
interconnection points, of which 69 are at or above 69 kV and to ERCOT via two high voltage direct
current (HVDC) ties. These interconnections provide an electric pathway to provide access to off-system
resources, as well as a delivery mechanism to neighboring systems.
4.4.2 Current AEP-SPP Transmission System Issues
Historically, the AEP SPP Transmission System was planned to deliver operating company
generation to their respective loads, as well as to provide interconnections with neighboring utilities
AEP-SPP 2009 Integrated Resource Plan
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for replacement and emergency power exchanges when needed and available. With the creation of
the SPP Regional Transmission Organization (RTO), the system is primarily planned under the
current SPP Transmission Expansion Plan (STEP) annual process for reliability and transmission
owner projects. The STEP process also identifies transmission reliability improvements to
accommodate approved transmission service and approved economic upgrades on an annual basis
looking out over a ten year period. SPP RTO’s process addresses transmission service needs to
deliver energy to loads and generation interconnection requests in separate studies. Going forward,
the SPP RTO will be using an Integrated Transmission Planning (ITP) process that is being
developed.
The limited capacity of interconnections between SPP and neighboring systems, as well as the
electrical topology of the SPP footprint transmission system, influences the ability to deliver non-affiliate
generation, both within and external to the SPP footprint, to AEP-SPP loads and from
sources within AEP-SPP balancing authority to serve AEP-SPP loads. Moreover, a lack of seams
agreements between SPP and its neighbors has significantly slowed down the process of developing
new interconnections. Despite the robust nature of the AEP-SPP transmission system as originally
designed, its current use is in a different manner than originally designed, in order to meet SPP RTO
requirements, which can stress the system. In addition, factors such as outages, extreme weather, and
power transfers also stresses the system. This has resulted in a transmission system in the AEP-SPP
zone that is constrained when generation is dispatched in a manner inconsistent with the original
design of utilizing local generation to serve local load. The resulting use of the AEP-SPP system is
inconsistent with the assumptions used to develop the models AEP provides to SPP to develop and
plan the system. SPP uses models provided by all load serving entities to study the reliability needs
of the SPP footprint. As discussed above, SPP currently uses separate modeling and studies to
address transmission service and interconnection requests.
4.4.2.1 The SPP Transmission Planning Process
Currently, SPP produces an annual SPP transmission expansion plan (STEP) that includes a ten
year system forecast. The STEP is developed through an open stakeholder process with AEP
participation. SPP studies the transmission system, checking for base case and contingency overload
and voltage violations in all of the SPP base case load flow models, plus models which include power
transfers biased in the various transfer directions.
The 2008 STEP summarizes 2008 activities, including expansion planning and long-term SPP
Open Access Transmission Tariff studies (Tariff Studies) that impact future development of the SPP
transmission grid. Six key topics are included in the STEP:
1) Tariff Studies,
2) Regional reliability assessment 2009-2018,
3) Subregional and local area planning,
4) High priority economic studies,
5) Interregional coordination; and
6) Project tracking.
AEP-SPP 2009 Integrated Resource Plan
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These topics are critical to meeting mandates of either the SPP strategic plan or the nine
planning principles in FERC Order 890. As a RTO under the domain of the Federal Energy
Regulatory Commission (FERC), SPP must meet requirements of FERC and the SPP Open Access
Transmission Tariff (OATT or Tariff). The SPP RTO acts independently of any single market
participant or class of participants. It has sufficient scope and configuration to maintain electric
reliability, effectively perform its functions, and support efficient and non-discriminatory power
markets. Regarding short-term reliability, the SPP RTO has the capability and exclusive authority to
receive, confirm, and implement all interchange schedules. It also has operational authority for all
transmission facilities under its control. The 10-year RTO regional reliability assessment continues to
be a primary focus.
STEP projects are categorized by the following designations:
 Economic: Projects identified for economic benefit;
 Generation Interconnect – Projects associated with a FERC-filed Interconnection
Agreement;
 Interregional- Projects developed with neighboring Transmission Providers;
 Regional reliability - Base Plan projects needed to meet the reliability of the region;
 Transmission service – Projects associated with a FERC-filed Service Agreement; and
 Zonal Reliability - Projects identified to meet more stringent local Transmission Owner
criteria.
The 2008 STEP identified approximately $2.7 billion of transmission Network Upgrades.
These include Network Upgrades required for NERC Reliability Standards or SPP Criteria; Zonal
Reliability Upgrades (compliance to Transmission Owner company-specific planning criteria);
requests for transmission service under the Tariff with a FERC-filed Service Agreement; and
generation interconnections with a FERC-filed interconnection agreement.
In addition, the SPP Regional State Committee and SPP Board of Directors/Members
Committee approved a long-awaited group of extra high voltage economic transmission expansion
upgrade projects totaling over $700 million, to be funded by FERC-approved "postage stamp" rates,
applicable to SPP's transmission-owning members across the region. The adjusted production cost
benefits of this group of transmission upgrades have been demonstrated by model analysis to
outweigh the costs (benefits greater than costs), thus achieving a "balanced portfolio" of projects. A
portfolio approach alleviates potential disputes that may arise from the construction of a single project
that may benefit one zone but not others. The balanced portfolio includes five new 345 kV
transmission lines, a 345 kV transformer, and a new connection between two existing 345 kV lines.
Details of the balanced portfolio results can be found at:
http://www.spp.org/publications/2009%20Balanced%20Portfolio%20-%20Final%20Approved%20Report.pdf
The SPP Board of Directors also recently approved a new report, prepared by the Synergistic
Planning Project Team that recommends restructuring the organization's regional planning processes
to focus on the construction of a robust transmission system, large enough in both scale and
geography to provide flexibility to meet SPP's future needs. The new Integrated Transmission
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Planning (ITP) process is intended to integrate or replace the STEP, balanced portfolio, and the Extra-
High Voltage Overlay process.
4.4.2.2 PSO-SWEPCO Interchange Capability
Operational experience and internal assessments of company transmission capabilities indicate
that, when considering a single contingency outage event, the present firm capability transfer limit
from PSO to SWEPCO is about 200 MW, and from SWEPCO to PSO is about 900 MW. As much as
900 MW may be available bi-directionally for economical energy transfers when no transmission
facilities are out of service. However, the intra-company available transmission capability between
the two companies is available to all transmission users under the provisions established by FERC
Order 888 and subsequent orders. Thus, there is some question as to whether, in the future, as SPP
grants further transmission rights, any transfer capability will in fact be available without further
upgrades to the transmission system.
Increasing the firm transfer capability from PSO to SWEPCO beyond about 200 MW may not
be cost-effective. As previously indicated each, company’s capacity additions are planned so that
each meets its own reserve requirement over the long-term. Any capacity transfers (i.e. “reserve
sharing”) should be considered for short time frames only. Specifically, the practice has been that, as
the last step of the planning process, the respective PSO and SWEPCO expansion plans are adjusted
to take advantage of any surplus of one company that might match a potential deficit of the other, and
thereby delay some of the identified new capacity. Because of the sizes, demand growth rates, and
peak coincidence of the two companies, it rarely appears that either company would ever have more
than 200 MW of surplus capacity in any year that could be transferred to the other company.
4.4.2.3 AEP-SPP Import Capability
Currently the transmission system cannot accommodate incremental firm imports to the AEP-SPP
area, based on preliminary AEP studies. Generally, the transfers are limited by the facilities of
neighboring systems rather than by transmission lines or equipment owned by AEP.
Increasing the import capabilities with AEP-SPP’s neighboring companies could require a large
capital investment for new transmission facilities by the neighboring systems or through sponsored
upgrades by SPP transmission owners. An analysis of the cost of the upgrades cannot be performed
until the capacity resources are determined. For identified resources, the cost of any transmission
upgrades necessary on AEP’s transmission system can be estimated by AEP once SPP has identified
the upgrade. AEP’s Southwest Transmission Planning group can identify constraints on third-party
systems through ad hoc power flow modeling studies, but Southwest Transmission Planning does not
have information to provide estimates of the costs to alleviate those third-party constraints.
4.4.2.4 SPP Studies that may Provide Import Capability
Besides the annual STEP process, SPP also performs other special studies or area studies on an
as needed basis. Two recent SPP studies could in time lead to improved transfer capability between
AEP-SPP and neighboring companies and regions.
AEP-SPP 2009 Integrated Resource Plan
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4.4.2.4.1 EHV Overlay Study
SPP hired a consultant, Quanta, to determine if SPP should build a 345, 500 or 765 kV overlay
to the existing SPP footprint. As of May 2008, the most recent version of this EHV Overlay Study
included plans for construction of a 765 kV transmission system across much of SPP that would
accommodate 13.5 GW of wind generation resources. One 765 kV loop would encompass much of
the Texas Panhandle and portions of western Oklahoma. Another 765 kV loop would encompass
much of the Oklahoma Panhandle and southwestern Kansas. These loops could be used to connect
large amounts of potential wind generation and wind generation in the generation interconnection
queue to the transmission grid. From these loops, two 765 kV paths would be extended, one to
Lawton and Muskogee, Oklahoma, and then northward toward the Kansas City area; the other to
Wichita, Kansas and eastward toward the Kansas City area. The 765 kV system would also extend
eastward with two 765 kV lines, one to the southeast to Entergy and one to the northeast to
Associated Electric Cooperative, Inc. (AECI). The plan also includes a new 500 kV line extending
eastward from Oklahoma Gas and Electric’s (OG&E) Fort Smith Station across central Arkansas to
Entergy, a large amount of 345 kV in northwestern Arkansas and southwestern Missouri, and five 345
kV lines in Kansas and Oklahoma. The total cost to implement the plan is approximately $8 billion.
The future of the overlay is uncertain. SPP performed an economic analysis of the original overlay
study. However, routing changes to the original projects have been proposed since the inclusion of
the Nebraska entities into SPP and the study is not yet completely vetted among stakeholders. From
an AEP perspective, the proposed overlays in the various study versions would enhance bulk power
transfers among the involved regions, but it is not known what additional, local facilities would be
required to create increased import capability. The SPP Board of Directors has yet to approve an
overlay plan but is now looking at a new synergistic integrated transmission planning process that
may incorporate the results of the study.
4.4.2.4.2 Ozark Transmission Study
This study, completed by SPP in June 2007, provides a long-range plan for the northern
Arkansas and southern Missouri region and provides guidance for future reinforcements to the
transmission system in this area. The recommendations include 500 kV lines from Entergy’s
Arkansas Nuclear One Station to OG&E’s VBI Station to AEP’s South Fayetteville Station. The
recommendations also included a 345 kV loop around the Fayetteville / Springdale area of
northwestern Arkansas as well as 345 kV expansion eastward to SWPA’s Table Rock Station located
in southwestern Missouri. From Table Rock Station, 345 kV lines to AECI’s Gobbler Knob Station
in southeastern Missouri and City Utilities of Springfield’s Brookline Station in southwestern
Missouri were also recommended. AEP and Arkansas Electric Cooperative Corporation (AECC)
have asked SPP to further study the 345 kV loop around the south side of the Fayetteville / Springdale
area as a complex priority project.
4.4.3 Recent AEP-SPP Bulk Transmission Improvements
Over the past several years, there have been several major transmission enhancements initiated
to reinforce the AEP-SPP transmission system. These enhancements include:
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 Northwest Arkansas— Northwest Arkansas is one of the fastest growing areas on the
AEP-SPP Transmission System. The approximate 1,200 MW of load in this area, about
47% of which is AECC retail load, is supplied primarily by the SWEPCO and AECC
jointly-owned Flint Creek generating plant, the SWEPCO Mattison generating plant, the
GRDA-Flint Creek 345 kV line, and the Clarksville-Chambers Spring 345 kV line. Wal-
Mart’s international headquarters and its supplying businesses’ offices and Tyson’s
headquarters are all located in this area. A significant conversion of the 69 kV transmission
system to 161 kV and extensive rebuilding and upgrading of portions of the existing 161 kV
system have been completed in recent years. In May 2008, the conversion of the 69 kV line
between Dyess and South Fayetteville stations to 161 kV and the construction of a new 345
kV line between Chambers Spring and Tontitown stations were completed. In May 2009, a
rebuild and reconductoring of the Flint Creek-Motley Road 161 kV line section was also
completed.
 Port of Shreveport (Port), Louisiana— A 138 kV loop is under construction, in phases,
around the Port to increase system reliability and to serve the increasing area load. In May
2008, a six -mile 138 kV transmission line was completed from Wallace Lake Station to
Port Robson Station to supply new loads under development at the Port. The 138 kV loop
has been extended from Port Robson Station to Bean Station and was further extended to
Caplis Station in June 2009. A 138 kV line approximately 23 miles long, connecting Caplis
Station to Red Point Station is also planned to complete the 138 kV loop. Together, these
improvements will supply power to the Port and the new distribution station site near
Caplis; correct contingency low voltage and thermal overloads in Bossier City, Louisiana
and the vicinity; and supply a second feed to Bean, Caplis, McDade, and Haughton stations.
This loop is currently expected to be completed in 2012.
 Shreveport line upgrades for Stall Plant generation addition – Several 138 kV and 69
kV lines in Shreveport, Louisiana have been or are being upgraded to accommodate the
Stall generation unit that is to be added at the Arsenal Hill Power Plant.
4.4.4 Impacts of New Generation:
There has been significant growth of approximately 5,700 MW of merchant generation in the
AEP-SPP zone. The total generation connected to the AEP-SPP Transmission System, including
electric cooperative generation, is approximately 15,600 MW. Integration of additional generation
capacity within the AEP-SPP zone will likely require significant transmission upgrades. At most
locations, any additional generation resources will aggravate existing transmission constraints.
Specifically:
 Western Oklahoma/Texas Panhandle—there are very few EHV transmission lines in this
area. In fact, transmission facilities above 69 kV are limited. However, the area is one of
the highest wind density areas within the SPP RTO footprint. The potential wind farm
capacity for this area has been estimated to exceed 4,000 MW. Several wind farms have
already been built, and several more are in the development stages. Wind generation
additions in the SPP footprint in this region will likely require significant transmission
AEP-SPP 2009 Integrated Resource Plan
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enhancements, including EHV line and station construction, to address thermal, voltage, and
stability constraints.
 PSO/SWEPCO Interface - There is one 345 kV EHV line linking PSO’s service area with
the majority of SWEPCO’s generation resources in its service area. Until recently,
constraints on the underlying transmission system limited the amount of firm generation that
can flow from PSO to SWEPCO and from SWEPCO to PSO to approximately zero in a
single contingency situation. However, an SPP approved project to rebuild the Danville to
North Magazine 161 kV line will increase the transfer capability from SWEPCO to PSO to
approximately 900 MW when completed in the Summer of 2009. Also, an SPP approved
project to rebuild the Broken Bow to Craig Junction 138 kV line has been completed and
has increased the transfer capability from PSO to SWEPCO to approximately 200 MW.
Significant generation additions to the AEP-SPP transmission facilities (or connection to
neighbor’s facilities) may require significant transmission enhancements, possibly including
EHV line and station construction, to address thermal, voltage, and stability constraints.
 Tulsa Metro Area—the Tulsa metro area load is supplied primarily by the PSO
Northeastern, Riverside, and Tulsa Power Station generating plants. Additionally,
Oklahoma Gas & Electric Company has large generation plants located to the southeast and
southwest of Tulsa, and there are large merchant plants just east and south of Tulsa. The
Grand River Dam Authority has a large plant located to the east of Tulsa. Generation
additions in the Tulsa area would likely require significant enhancements in the EHV and
sub-transmission system to address thermal, voltage and stability constraints.
 SPP Eastern Interface—there are only five east-west EHV lines into the SPP region,
which stretches from the Gulf of Mexico (east of Houston) north to Des Moines, Iowa. This
limitation constrains the amount of imports and exports along the eastern interface of SPP
with neighboring regions. It also constrains the amount of transfers from the capacity rich
western SPP region to the market hubs east and north of the SPP RTO region. Significant
generation additions near or along the SPP eastern interface would likely require significant
transmission enhancements, including EHV line and station construction, to address thermal
and stability constraints should such generation additions adversely impact existing
transactions along the interface. SPP has addressed some of these potential ties in the EHV
Overlay Study discussed above.
Integration of generation resources at any location within the AEP-SPP zone will require
significant analysis by SPP to identify potential thermal, short circuit, and stability constraints
resulting from the addition of generation. Depending on the specific location, EHV line and station
construction, in addition to connection facilities, could be necessary. Other station enhancements,
including transformer additions and breaker replacements may be necessary. Some of the required
transmission upgrades could be reduced or increased in scope if existing generating capacity is retired
concurrent with the addition of new capacity.
4.4.5 Horizon Transmission LLC, Joint Venture in the SPP
On July 15, 2008, Electric Transmission America (ETA), a joint venture of American Electric
Power and MidAmerican Energy Holdings, formed a joint venture company with OGE Energy Corp.
AEP-SPP 2009 Integrated Resource Plan
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to build and own new electric transmission assets